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UNITED
STATES
SECURITIES
AND EXCHANGE COMMISSION
Washington,
D.C. 20549
 
FORM
10-K
 



☒
ANNUAL
    REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 
For
the fiscal year ended March 31, 2024 
 


☐
TRANSITION
    REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 
Commission
File No. 1-31785
 
MEXCO
ENERGY CORPORATION
(Exact
name of registrant as specified in its charter)
 


Colorado
 
84-0627918

(State
    or other jurisdiction of incorporation or organization)
 
(I.R.S.
    Employer Identification No.)

 
 
 

415
W. Wall, Suite 475
 
(432)
682-1119

Midland,
    Texas 79701
 
(Registrant’s
telephone number, including area code)

(Address
of principal executive offices, Zip Code)
 
 

 
Securities
registered pursuant to Section 12(b) of the Act: None
 
Securities
registered pursuant to Section 12(g) of the Act:
 


Title
    of each class
 
Trading
    Symbol(s)
 
Name
    of each exchange on which registered 

Common
    Stock, par value $0.50 per share
 
MXC
 
NYSE
    American

 
Indicate
by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒
 
Indicate
by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. ☐
 
Indicate
by check-mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding twelve (12) months (or for such shorter period that the registrant was required to file such reports)
and (2) has been subject to such filing requirements for the past ninety (90) days. Yes ☒ No ☐
 
Indicate
by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data
File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding
12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
 
Indicate
by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting
company, or and emerging growth company. See definitions of “large accelerated filer”, “accelerated filer”, “smaller
reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act:
 
Large
Accelerated Filer ☐ Accelerated Filer ☐ Non-Accelerated Filer ☒ Smaller Reporting Company ☒ Emerging Growth Company
☐
 
If
an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying
with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
 
Indicate
by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness
of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered
public accounting firm that prepared or issued its audit report. ☐
 
If
securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant
included in the filing reflect the correction of an error to previously issued financial statements. ☐
 
Indicate
by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation
received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.1D-1(b). ☐
 
Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
 
The
aggregate market value of the voting stock held by non-affiliates of the Registrant as of September 30, 2023 (the last business day of
the Registrant’s most recently completed second quarter) was $14,672,667 as computed by reference to the last reported sale.
 
There
were 2,090,000 shares of the registrant’s common stock outstanding as of June 27, 2024.
 
DOCUMENTS
INCORPORATED BY REFERENCE
 
Portions
of the Registrant’s Proxy Statement relating to the 2024 Annual Meeting of Shareholders to be held on September 10, 2024, have
been incorporated by reference in Part III of this Form 10-K. Such Proxy Statement will be filed with the Commission not later than 120
days after March 31, 2024, the end of the fiscal year covered by this report.
 

 
 

 
 

 
TABLE
OF CONTENTS
 


Cautionary Note Regarding Forward-Looking Statements
3

 
 
 

PART I
 
 

 
 
 

Item
    1.
Business

3

Item
    1A.
Risk Factors
10

Item
    1B.
Unresolved Staff Comments
15

Item 1C. 
Cybersecurity
15

Item
    2.
Properties
16

Item
    3.
Legal Proceedings
20

Item
    4.
Mine Safety Disclosures
20

 
 
 

PART II
 
 

 
 
 

Item
    5.
Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
21

Item
    6.
Reserved

22

Item
    7.
Management’s Discussion and Analysis of Financial Condition and Results of Operations
23

Item
    7A.
Quantitative and Qualitative Disclosures About Market Risk
30

Item
    8.
Financial Statements and Supplementary Data
31

Item
    9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosures
31

Item
    9A.
Controls and Procedures
31

Item
    9B.
Other Information
32

Item
    9C.
Disclosure Regarding Foreign Jurisdictions that Prevent Inspection
32

 
 
 

 
 
 

PART III
 
 

 
 
 

Item
    10.
Directors, Executive Officers and Corporate Governance
32

Item
    11.
Executive Compensation
32

Item
    12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
32

Item
    13.
Certain Relationships and Related Transactions, and Director Independence
32

Item
    14.
Principal Accounting Fees and Services
32

 
 
 

PART IV
 
 

 
 
 

Item
    15.
Exhibits and Financial Statement Schedules 
33

Item
    16.
Form 10-K Summary 
33

 
 
 

Signatures
 
34

 
 
 

Glossary of Abbreviations and Terms
35

 

2
 

 
As
used in this document, “the Company”, “Mexco”, “we”, “us” and “our” refer
to Mexco Energy Corporation and its consolidated subsidiaries.
 
Abbreviations
or definitions of certain terms commonly used in the oil and gas industry and in this Form 10-K can be found in the “Glossary of
Abbreviations and Terms”.
 
CAUTIONARY
NOTE REGARDING FORWARD-LOOKING STATEMENTS
 
This
Annual Report on Form 10-K contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended,
(the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended, (the “Exchange Act”).
These forward-looking statements are generally located in the material set forth under the headings “Risk Factors”, “Management’s
Discussion and Analysis of Financial Condition and Results of Operations”, “Business”, “Properties” but
may be found in other locations as well, and are typically identified by the words “could”, “should”, “expect”,
“project”, “estimate”, “believe”, “anticipate”, “intend”, “budget”,
“plan”, “forecast”, “predict” and other similar expressions.
 
Forward-looking
statements generally relate to our profitability; planned capital expenditures; estimates of oil and gas production; future project dates;
estimates of future oil and gas prices; estimates of oil and gas reserves; our future financial condition or results of operations; and
our business strategy and other plans and objectives for future operations and are based upon our management’s reasonable estimates
of future results or trends. Actual results in future periods may differ materially from those expressed or implied by such forward-looking
statements because of a number of risks and uncertainties affecting our business, including those discussed in “Risk Factors”.
The factors that may affect our expectations regarding our operations include, among others, the following: our success in development,
exploitation and exploration activities; our ability to make planned capital expenditures; declines in our production or prices of oil
and gas; our ability to raise equity capital or incur additional indebtedness; our restrictive debt covenants; our acquisition and divestiture
activities; weather conditions and events; the proximity, capacity, cost and availability of pipelines and other transportation facilities;
increases in the cost of drilling, completion and gas gathering or other costs of production and operations; and other factors discussed
elsewhere in this document. We disclaim any intention or obligation to update or revise any forward-looking statements as a result of
new information, future events or otherwise.
 

PART
I
 


ITEM
  1.
BUSINESS

 
General
 
Mexco
Energy Corporation, a Colorado corporation, is an independent oil and gas company engaged in the acquisition, exploration, development
and production of crude oil and natural gas properties located in the United States. Incorporated in April 1972 under the name Miller
Oil Company, the Company changed its name to Mexco Energy Corporation effective April 30, 1980. At that time, the shareholders of the
Company also approved amendments to the Articles of Incorporation resulting in a one-for-fifty reverse stock split of the Company’s
common stock.
 
Our
total estimated proved reserves at March 31, 2024 were approximately 1.547 million barrels of oil equivalent (“MMBOE”) of
which 51% was oil and natural gas liquids and 49% was natural gas, and our estimated present value of proved reserves was approximately
$29 million based on estimated future net revenues excluding taxes discounted at 10% per annum, pricing and other assumptions set forth
in “Item 2 – Properties” below.
 
Nicholas
C. Taylor beneficially owns approximately 45% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board
and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the
election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business
strategy and daily operations.
 


3
 

 

Company
Profile
 
Since
our inception, we have been engaged in acquiring and developing oil and gas properties and the exploration for and production of natural
gas, crude oil, condensate and natural gas liquids (“NGLs”) within the United States. We especially seek to acquire proved
reserves that fit well with existing operations or in areas where Mexco has established production. Acquisitions preferably will contain
most of their value in producing wells, behind pipe reserves and high quality proved undeveloped locations. Competition for the purchase
of proved reserves is intense. Sellers often utilize a bid process to sell properties. This process usually intensifies the competition
and makes it extremely difficult to acquire reserves without assuming significant price and production risks. We actively search for
opportunities to acquire proved oil and gas properties. However, because the competition is intense, we cannot give any assurance that
we will be successful in our efforts during fiscal 2025.
 
While
we own oil and gas properties in other states, the majority of our activities are centered in West Texas and Southeastern New Mexico.
The Company also owns producing properties and undeveloped acreage in fourteen states. We acquire interests in producing and non-producing
oil and gas leases from landowners and leaseholders in areas considered favorable for oil and gas exploration, development and production.
In addition, we may acquire oil and gas interests by joining in oil and gas drilling prospects generated by third parties. We may also
employ a combination of the above methods of obtaining producing acreage and prospects. In recent years, we have placed primary emphasis
on the evaluation and purchase of producing oil and gas properties, including working, royalty and mineral interests, and prospects that
could have a potentially meaningful impact on our reserves. All of the Company’s oil and gas interests are operated by others.
 
From
1983 to 2024, Mexco Energy Corporation made numerous acquisitions of royalties, overriding royalties, minerals and working interests
in producing oil and gas properties including the following most significant acquisitions:
 


1990-1994
Royalty
    interests, aggregate purchase price of approximately $501,000 covering multiple wells in the Gomez (Ellenberger) Field of Pecos County,
    Texas. 

 
 

1993-2014
Tabbs
    Bay Oil Company and Thompson Brothers Lumber Company, respectively dissolved in 1957 and 1947. Purchase covering thousands of acres
    located respectively in 19 counties of Texas, 3 parishes of Louisiana and one county in Arkansas and 8 counties of Texas, respectively
    consisting of various mineral, royalty and overriding royalty interests.

 


1997
    
Forman
    Energy Corporation, purchase price of $1,591,000 consisting primarily of working interests in approximately 634 wells located in
    12 states.

 
 

2004
Royalty
    interests, purchase price $304,000 covering 37 producing wells in the Cotton Valley formation in Limestone County, Texas and the
    Lower Cotton Valley formation in Jackson Parish, Louisiana. This acreage also contains additional potential undrilled locations. 

 
 

 
Royalty
    interests, purchase price $500,000 covering 4 producing gas units in Freestone County, Texas containing 33 producing wells and additional
    potential undeveloped locations in the Cotton Valley formation.

 
 

2005
Royalty
    interests, purchase price $550,000 covering 75 producing wells and additional potential undeveloped locations
    in the Cotton Valley formation of Freestone and Limestone Counties, Texas. 

 
 

2007
Non-operated
    working interests, purchase price $425,000 covering 2 properties in Lea County, New Mexico. 

 
 

 
Royalty
    (mineral) acreage, purchase price $1,850,000 covering 122 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County,
    Texas amounting to approximately 21.45% royalty interest. 

 
 

2008
Royalty
    (mineral) acreage, purchase price $429,000 covering 522 mineral acres in the Newark East (Barnett Shale) Field of Tarrant County,
    Texas containing 6 producing natural gas wells and additional potential undeveloped well locations.
    In March 2009, purchased additional interests, $49,000.

 
 


4
 

 


2010
    
Southwest
    Texas Disposal Corporation, purchase price $478,000 consisting of royalty interests in over 300 wells located in 60 counties and
    parishes of 6 states.

 
 

 
Overriding
    royalty interests, purchase price $1,650,000 covering 5,120 gross acres over 8 sections in the Haynesville trend area of DeSoto Parish,
    Louisiana containing 6 horizontal producing wells and additional potential undeveloped drill sites. The Company paid
    $1.46 million in cash and the remainder was paid as 26,833 shares of its common stock issued from treasury shares. 

 
 

2011
Non-operating
    working interests, purchase price $670,000 covering 160 gross acres in the Fuhrman-Mascho Field of Andrews County, Texas containing
    5 producing wells in the Grayburg and San Andres formations and additional potential drill sites. In March 2012, purchased additional
    working interests, $275,000. 

 
 

2012
TBO
    Oil and Gas, LLC, purchase price of $1,150,000 consisting of working interests in approximately 280 wells located in 16 counties
    of 3 states.

 
 

2014
Royalty
    interests, purchase price $200,000 covering 43 wells in 12 counties of 8 states, primarily in Texas. 

 
 

 
Royalty
    interests, purchase price $580,000 covering 580 wells in 87 counties of 8 states. Approximately 90% of the net revenue from these
    royalties is produced by 157 wells located in the Barnett Shale of the Fort Worth Basin of Texas. 

 
 

 
Royalty
    and mineral interests, purchase price $1,000,000 covering approximately 1,800 wells in 27 counties of Texas. Of these oil and gas
    reserves, approximately 60% is natural gas and 40% oil. 

 
 

 
Non-Operated
    working interests, purchase price $840,000 in 70 Natural gas producing wells located in 5 counties of Oklahoma.

 
 

 
Non-Operated
    working interests, purchase price $200,000 covering 80 wells located in Hockley and Pecos Counties, Texas.

 
 

 
Non-Operated
    working interests, purchase price $450,000 covering 43 wells in Webster Parish, Louisiana; Eddy County, New Mexico; and, Nolan and
    Smith Counties, Texas.

 
 

2019
Royalty
    interest investment, $300,000 for a less than 1% investment commitment in a limited liability company, capitalized at approximately
    $50 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. This LLC has returned
    $276,098 and 92% of the total investment since inception in fiscal 2020. 

 



2022-2023
Overriding
    royalty interests, purchase price of $567,000 covering 53 producing wells and several additional potential locations for development
    in Atascosa and Karnes Counties, Texas. 

 
 

 
Royalty
    interests, purchase price of $939,000 covering 22 producing wells and several additional potential locations for development in the
    Eagleford area of Dimmit County, Texas. 

 
 

 
Royalty
    interest investment, $2,000,000 for an approximate 2% investment commitment in a limited liability company, capitalized at approximately
    $100 million to purchase royalty interests consisting of minerals located in the Marcellus and Utica areas of Ohio. As of the date
    of this report, $1,000,000 of the commitment has been expended. 

 
 

 
Royalty
    interests, purchase price of $117,200 covering 28 producing wells in 6 counties in the Haynesville trend area of Louisiana and 5
    counties in Texas. 

 
 

2023-2024
Royalty
    interests, purchase price of $455,000 covering 8 producing wells and additional potential locations for development in Reeves County,
    Texas. 

 
 

 
Royalty
    interests, purchase price of $367,500 covering 84 producing wells and additional potential locations for development in 6 counties
    in Texas. 

 
 

 
Royalty
    interest, purchase price of $575,600 covering 9 producing wells with additional potential locations for development and 4 producing
    wellbores in Weld County, Colorado. 

 
 

 
Royalty
    interests, purchase price of $390,300 covering 255 producing wells in the Haynesville trend area of Caddo Parish, Louisiana. 

 

5
 

 
Industry
Environment and Outlook
 
The
commodity price environment was challenging in fiscal 2024. The war in Ukraine and the Israel-Hamas war, rising interest rates, global
supply chain disruptions, concerns about a potential economic downturn or recession and measures to combat persistent inflation and instability
in the financial sector have contributed to recent economic and pricing volatility and may continue to impact pricing throughout fiscal
2025. In light of these challenges facing our industry and in response to the continued challenging environment, our primary business
strategies for fiscal 2025 will continue to include: (1) optimizing cash flows through operating efficiencies and cost reductions, (2)
divesting of non-core assets, and (3) working to balance capital spending with cash flows to minimize borrowings and maintain ample liquidity.
 
See
Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations for discussion of our fiscal
2024 operating results and potential impact on fiscal 2025 operating results due to commodity price changes.
 
Oil
and Gas Operations
 
As
of March 31, 2024, oil constituted approximately 83% of our oil and natural gas sales and approximately 51% of our total proved reserves
volumes for fiscal 2024. Revenues from oil and gas royalty interests accounted for approximately 28% of our total operating revenues
for fiscal 2024.
 
There
are two primary areas in which the Company is focused, 1) the Delaware Basin located in the Western portion of the Permian Basin including
Lea and Eddy Counties, New Mexico and Reeves and Loving Counties, Texas and 2) the Midland Basin located in the Eastern portion of the
Permian Basin including Reagan, Upton, Midland, Martin, Howard and Glasscock Counties, Texas. The Permian Basin in total accounts for
85% of our discounted future net cash flows from proved reserves and 87% of our gross revenues.
 
The
Permian Basin is one of the oldest and most prolific producing basins in North America which has been a significant source of oil production
since the 1920s. The Permian Basin is known to have a number of zones of oil and natural gas bearing rock throughout.
 
The
Delaware Basin properties, encompassing 39,112 gross acres, 213 net acres, 742 gross producing wells or 4 net wells account for approximately
70% of our discounted future net cash flows from proved reserves as of March 31, 2024. For fiscal 2024, these properties accounted for
62% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 29% are attributable to proven
undeveloped reserves which would be developed through new drilling.
 
The
Midland Basin properties, encompassing 115,030 gross acres, 249 net acres, 1,731 gross producing wells or 5 net wells account for approximately
13% of our discounted future net cash flows from proved reserves as of March 31, 2024. For fiscal 2024, these properties accounted for
23% of our gross revenues. Of these discounted future net cash flows from proved reserves, approximately 5% are attributable to proven
undeveloped reserves which would be developed through new drilling.
 
Mexco
believes its most important properties for future development by horizontal drilling and hydraulic fracturing area are located in Lea
and Eddy Counties, New Mexico of the Delaware Basin and the Midland Basin in Midland, Reagan and Upton Counties, Texas.
 
For
more on these and other operations in this area see “Item 7. Management’s Discussion and Analysis of Financial Condition
and Results of Operations – Liquidity and Capital Resources Commitments”.
 
We
own partial interests in approximately 6,800 producing wells all of which are located within the United States in the states of Texas,
New Mexico, Oklahoma, Louisiana, Alabama, Mississippi, Arkansas, Wyoming, Kansas, Colorado, Montana, Virginia, North Dakota, and Ohio.
Additional information concerning these properties and our oil and gas reserves is provided below.
 

6
 

 
The
following table indicates our oil and gas production in each of the last five years:
 


Year 
Oil(Bbls)  
Gas (Mcf) 

2024 
 69,999  
 502,879 

2023 
 73,968  
 534,363 

2022 
 61,689  
 393,841 

2021 
 50,327  
 324,205 

2020 
 44,301  
 294,007 

 
Competition
and Markets
 
The
oil and gas industry is a highly competitive business. Competition for oil and gas reserve acquisitions is significant. We may compete
with major oil and gas companies, other independent oil and gas companies and individual producers and operators, some of which have
financial and personnel resources substantially in excess of those available to us. As a result, we may be placed at a competitive disadvantage.
Competitive factors include price, contract terms and types and quality of service, including pipeline distribution. The price for oil
and gas is widely followed and is generally subject to worldwide market factors. Our ability to acquire and develop additional properties
in the future will depend upon our ability to evaluate and select suitable properties and to consummate transactions in this highly competitive
environment in a timely manner.
 
In
addition, the oil and gas industry as a whole also competes with other industries in supplying the energy and fuel requirements of industrial,
commercial and individual consumers. The price and availability of alternative energy sources could adversely affect our revenue.
 
Market
factors affect the quantities of oil and natural gas production and the price we can obtain for the production from our oil and natural
gas properties. Such factors include: the extent of domestic production; the level of imports of foreign oil and natural gas; the general
level of market demand on a regional, national and worldwide basis; domestic and foreign economic conditions that determine levels of
industrial production; political events in foreign oil-producing regions; and variations in governmental regulations including environmental,
energy conservation and tax laws or the imposition of new regulatory requirements upon the oil and natural gas industry.
 
The
market for our oil, gas and natural gas liquids production depends on factors beyond our control including: domestic and foreign political
conditions; the overall level of supply of and demand for oil, gas and natural gas liquids; the price of imports of oil and gas; weather
conditions; the price and availability of alternative fuels; the proximity and capacity of gas pipelines and other transportation facilities;
and overall economic conditions.
 
Major
Customers
 
We
made sales that amounted to 10% or more of operating revenues as follows for the years ended March 31:
 


  
2024  
2023 

Company A 
 59% 
 53%

 
Historically,
the Company has not experienced significant credit losses on our oil and gas accounts and management is of the opinion that significant
credit risk does not exist. Because a ready market exists for oil and gas production, we do not believe the loss of any individual purchaser
would have a material adverse effect on our financial position or results of operations.
 

7
 

 
Environmental
Regulation
 
The
oil and gas industry is extensively regulated at the federal, state, and local levels. Regulations affecting elements of the energy sector
are under constant review for amendment or expansion and frequently more stringent requirements are imposed. Various federal and state
agencies, including the Texas Railroad Commission, the Bureau of Land Management (the “BLM”), an agency of the U.S Department
of the Interior (“DOI”), the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection
Agency (the “EPA”), the Department of Transportation (“DOT”) and the U.S. Occupational Safety and Health Administration
(“OSHA”), have legal and regulatory authority and oversight over the operations on the properties in which the Company owns
an interest.
 
Under
certain environmental laws and regulations, the operators of the Company properties could be subject to strict, joint and several liability
for the removal or remediation of property contamination, whether at a drill site or a waste disposal facility, even when the operators
did not cause the contamination or their activities were in compliance with all applicable laws at the time the actions were taken. The
Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), also known as the “superfund”
law, for example, imposes liability, regardless of fault or the legality of the original conduct, on certain classes of persons for releases
into the environment of a “hazardous substance.” Liable persons may include the current or previous owner and operator of
a site where a hazardous substance has been disposed and persons who arranged for the disposal of a hazardous substance at a site. Under
CERCLA and similar statutes, government authorities or private parties may take actions in response to threats to the public health or
the environment or sue responsible persons for the associated costs. In the course of operations, the working interest owner and/or the
operator of the Company properties may have generated and may generate materials that could trigger cleanup liabilities. In addition,
the Company properties have produced oil and/or natural gas for many years, and previous operators may have disposed or released hydrocarbons,
wastes or hazardous substances at the Company properties. The operator of the Company properties or the working interest owners may be
responsible for all or part of the costs to clean up any such contamination. Although the Company is not the operator of such properties,
its ownership of the properties could cause it to be responsible for all or part of such costs to the extent CERCLA or any similar statute
imposes responsibility on such parties as “owners.”
 
Various
state governments and regional organizations comprising state governments already have enacted legislation and promulgated rules restricting
greenhouse gases (“GHGs”) emissions or promoting the use of renewable energy, and additional such measures are frequently
under consideration. Although it is not possible at this time to estimate how potential future requirements addressing GHG emissions
would impact operations on the Company properties and revenue, either directly or indirectly, any future federal, state or local laws
or implementing regulations that may be adopted to address GHG emissions could require the operators of our properties to incur new or
increased costs to obtain permits, operate and maintain equipment and facilities, install new emission controls, acquire allowances to
authorize GHG emissions, pay taxes related to GHG emissions or administer a GHG emissions program. Regulation of GHGs could also result
in a reduction in demand for and production of oil and natural gas. Additionally, to the extent that unfavorable weather conditions are
exacerbated by global climate change or otherwise, the Company properties may be adversely affected to a greater degree than previously
experienced.
 
We
did not incur any material capital expenditures for remediation or pollution control activities for the year ended March 31, 2024. Additionally,
as of the date of this report, we are not aware of any environmental issues or claims that will require material capital expenditures
during fiscal 2025.
 
Other
Regulation
 
Other
agencies with certain authority over the Company’s business include the Internal Revenue Service (the “IRS”), the SEC
and NYSE. Ensuring compliance with the rules, regulations and orders promulgated by such entities requires extensive effort and incremental
costs to comply, which affects the Company’s profitability. Because public policy changes are commonplace, and existing laws and
regulations are frequently amended, the Company is unable to predict the future cost or impact of compliance. However, the Company does
not expect that any of these laws and regulations will affect its operations materially differently than they would affect other companies
with similar operations, size and financial strength.
 
Title
to Properties
 
The
leasehold properties we own are subject to royalty, overriding royalty and other outstanding interests customary in the industry. The
properties may be subject to burdens such as liens incident to operating agreements and current taxes, development obligations under
oil and gas leases and other encumbrances, easements and restrictions. We do not believe any of these burdens will materially interfere
with the use of these properties.
 

8
 


 
Prior
to drilling of an oil and natural gas well, it is normal practice in our industry for the person or company acting as the operator of
the well to obtain a preliminary title review to ensure there are no obvious defects in title to the well. Frequently, as a result of
such examinations, certain curative work must be done to correct defects in the marketability of the title, and such curative work entails
expense. Our operators’ failure to cure any title defects may delay or prevent us from utilizing the associated mineral interest.
We believe the title to our properties is good and defensible in accordance with standards generally acceptable in the oil and gas industry
subject to such exceptions that, in the opinion of counsel employed in the various areas in which we have activities, are not so material
as to detract substantially from the use of such properties.
 
Substantially
all of our properties are currently mortgaged under a deed of trust to secure funding through a credit facility.
 
Insurance
 
Our
operations are subject to all the risks inherent in the exploration for and development and production of oil and gas including blowouts,
fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from
uninsured risks or in amounts in excess of existing insurance coverage.
 
Executive
Officers 
 
The
following table sets forth certain information concerning the executive officers of the Company as of March 31, 2024.
 


Name
 
Age
 
Position

Nicholas
    C. Taylor
 
86
 
Chairman
    and Chief Executive Officer

Tamala
    L. McComic
 
55
 
President,
    Chief Financial Officer, Treasurer, and Assistant Secretary 

Donna
    Gail Yanko
 
79
 
Vice
    President 

Stacy
    D. Hardin
 
59
 
Secretary
    and Assistant Treasurer

 
Set
forth below is a description of the principal occupations during at least the past five years of each executive officer of the Company.
 
Nicholas
C. Taylor was elected Chairman of the Board and Chief Executive Officer of the Company in September 2011 and continues to serve in such
capacity on a part time basis, as required. He served as Chief Executive Officer, President and Director of the Company from 1983 to
2011. From July 1993 to the present, Mr. Taylor has been involved in the independent practice of law and other business activities. In
November 2005 he was appointed by the Speaker of the House to the Texas Ethics Commission and served until February 2010.
 
Tamala
L. McComic, a Certified Public Accountant and Chartered Global Management Accountant, became Controller for the Company in July 2001
and was elected President and Chief Financial Officer in September 2011. She served the Company as Executive Vice President and Chief
Financial Officer from 2009 to 2011 and Vice President and Chief Financial Officer from 2003 to 2009. Prior thereto, Ms. McComic served
as Treasurer and Assistant Secretary of the Company.
 
Donna
Gail Yanko was appointed to the position of Vice President of the Company in 1990. She also served as Corporate Secretary from 1992 to
2021 and from 1986 to 1992 was Assistant Secretary. From 1986 to 2015, on a part-time basis, she assisted the Chairman of the Board of
the Company in his personal business activities. Ms. Yanko also served as a director of the Company from 1990 to 2008.
 
Stacy
D. Hardin joined the Company in 2006 and was elected Corporate Secretary of the Company in September 2021. She has also served the Company
as Assistant Treasurer of the Company since 2010 and from 2006 to 2021 was Assistant Secretary. Prior thereto, Ms. Hardin served as Assistant
Controller.
 
Employees
 
As
of March 31, 2024, we had three full-time and three part-time employees. We believe that relations with these employees are generally
satisfactory. From time to time, we utilize the services of independent geological, land and engineering consultants on a limited basis
and expect to continue to do so in the future.
 

9
 

 
Office
Facilities 
 
Our
principal offices are located at 415 W. Wall, Suite 475, Midland, Texas 79701 and our telephone number is (432) 682-1119. We believe
our facilities are adequate for our current operations and future needs.
 
Access
to Company Reports
 
Mexco
Energy Corporation files annual, quarterly and current reports, proxy statements and other information with the SEC. The SEC maintains
an internet website (www.sec.gov) that contains annual, quarterly and current reports, proxy statements and other information that issuers,
including Mexco, file electronically with the SEC.
 
We
also maintain an internet website at www.mexcoenergy.com. In the Investor Relations section, our website contains our Annual Reports
on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports and amendments to those reports as soon
as reasonably practicable after such material is electronically filed with the SEC. Information on our website is not incorporated by
reference into this Form 10-K and should not be considered part of this report or any other filing that we make with the SEC. Additionally,
our Code of Business Conduct and Ethics and the charters of our Audit Committee, Compensation Committee and Nominating Committee are
posted on our website. Any of these corporate documents as well as any of the SEC filed reports are available in print free of charge
to any stockholder who requests them. Requests should be directed to our Corporate Secretary by mail to P.O. Box 10502, Midland, Texas
79702 or by email to mexco@sbcglobal.net.
 



ITEM
1A.

RISK FACTORS


 

The
Company is subject to various risks and uncertainties in the ordinary course of business. The following summarizes significant risks
and uncertainties that may adversely affect our business, financial condition or results of operations. We could also face additional
risks and uncertainties not currently known to us or that we currently deem to be immaterial. If any of these risks actually occurs,
it could materially harm our business, financial condition or results of operations and the trading price of our shares could decline.
Investors should carefully consider each of the following risk factors and all of the other information set forth in this Annual Report
on Form 10-K.

 
RISKS
RELATED TO OUR BUSINESS AND INDUSTRY
 
Volatility
of oil and gas prices significantly affects our results and profitability. 
 
Prices
for oil and natural gas fluctuate widely. We cannot predict future oil and natural gas prices with any certainty. Historically, the markets
for oil and gas have been volatile, and they are likely to continue to be volatile. Factors that can cause price fluctuations include
the level of global demand for petroleum products; foreign supply and pricing of oil and gas; the actions of OPEC, its members and other
state-controlled oil companies relating to oil price and production controls; nature and extent of governmental regulation and taxation,
including environmental regulations; level of domestic and international exploration, drilling and production activity; the cost of exploring
for, producing and delivering oil and gas; speculative trading in crude oil and natural gas derivative contracts; availability, proximity
and capacity of oil and gas pipelines and other transportation facilities; weather conditions; the price and availability of alternative
fuels; technological advances affecting energy consumption; national and international pandemics; and, overall political and economic
conditions in oil producing countries.
 
Increases
and decreases in prices also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise
additional capital. The amount we can borrow from banks may be subject to redetermination based on changes in prices. In addition, we
may have ceiling test writedowns when prices decline. Lower prices may also reduce the amount of crude oil and natural gas that can be
produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price changes
and not as a result of drilling or well performance.
 
Changes
in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction in reserves,
including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect the amount
of cash flow available for capital expenditures and our ability to obtain additional capital for our exploration and development activities.
 
Oil
and natural gas prices do not necessarily fluctuate in direct relationship to each other. Lower prices or lack of storage may have an
adverse affect on our financial condition due to reduction of our revenues, operating income and cash flows; curtailment or shut-in of
our production due to lack of transportation or storage capacity; cause certain properties in our portfolio to become economically unviable;
and, limit our financial condition, liquidity, and/or ability to finance planned capital expenditures and operations.
 

10
 

 
Our
results of operations may be negatively impacted by current global events.
 
The
United States and certain countries in Europe and Asia are facing economic struggles or slowing economic growth. If these conditions
worsen, combined with a decline in economic growth in other parts of the world, there could be a significant adverse effect on global
financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist
attacks in the United States or other countries could adversely affect the global economy. Global or national health concerns may adversely
affect the Company by (i) reducing demand for its oil, NGLs and gas because of reduced global or national economic activity, (ii) impairing
its supply chain (for example, by limiting manufacturing of materials used in operations) and (iii) affecting the health of its workforce,
rendering employees unable to work or travel. Deteriorating economic climate in the United States or abroad due to inflation, rising
interest rates or otherwise, demand for petroleum products could diminish or stagnate, which could depress the prices at which the Company
could sell its oil, NGLs and gas, affect the ability of the Company’s vendors, suppliers and customers to continue operations and
ultimately decrease the Company’s cash flows and profitability. In addition, reduced worldwide demand for debt and equity securities
issued by oil and gas companies may make it more difficult for the Company to raise capital to fund its operations or refinance its debt
obligations.
 
Changes
in environmental laws could increase our operators’ costs and adversely impact our business, financial condition and cash flows.
 
President
Biden has indicated that he is supportive of, and has issued executive orders promoting various programs and initiatives designed to,
among other things, curtail climate change, control the release of methane from new and existing oil and natural gas operations, and
decarbonize electric generation and the transportation sector. In recent years the U.S. Congress has considered legislation to reduce
emissions of GHGs, including methane, a primary component of natural gas, and carbon dioxide, a byproduct of the burning of natural gas.
For example, the Inflation Reduction Act of 2022 (the “IRA”), which appropriates significant federal funding for renewable
energy initiatives and, for the first time ever, imposes a fee on GHG emissions from certain facilities, was signed into law in August
2022. The emissions fee and funding provisions of the law could increase operating costs within the oil and gas industry and accelerate
the transition away from fossil fuels, which could in turn adversely affect our business and results of operations.
 
Governmental,
scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks
in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has
issued several executive orders focused on addressing climate change, including items that may impact costs to produce, or demand for,
oil and gas.
 
Lower
oil and gas prices and other factors may cause us to record ceiling test writedowns.
 
Lower
oil and gas prices increase the risk of ceiling limitation write-downs. We use the full cost method to account for oil and gas
operations. Accordingly, we capitalize the cost to acquire, explore for and develop crude oil and natural gas properties including
the cost of abandoned properties, dry holes, geophysical costs and annual lease rentals. Sales or other dispositions of oil and
natural gas properties are accounted for as adjustments to capitalized costs, with no gain or loss recorded. Depletion of evaluated
oil and natural gas properties is computed in the units of production method, whereby capitalized costs are amortized over total
proved reserves. Under the full cost accounting rules, the net capitalized cost of crude oil and natural gas properties may not
exceed a “ceiling limit” which is based upon the present value of estimated future net cash flows from proved reserves,
discounted at 10% plus the lower of cost or fair market value of unproved properties. If net capitalized costs of oil and natural
gas properties exceed the ceiling limit, we must charge the amount of the excess against earnings. This is called a “ceiling
test writedown.” We use the unweighted arithmetic average first day of the month price for oil and natural gas for the
12-month period preceding the calculation date in estimating discounted future net reserves. Under the accounting rules, we are
required to perform a ceiling test each quarter. A ceiling test writedown does not impact cash flow from operating activities, but
does reduce stockholders’ equity and earnings. The risk that we will be required to write down the carrying value of oil and
natural gas properties increases when oil and natural gas prices are low. There were no ceiling test impairments on our oil and gas
properties during fiscal 2024 and 2023.
 

11
 

 
We
must replace reserves we produce.
 
Our
future success depends upon our ability to find, develop or acquire additional, economically recoverable oil and gas reserves. Our proved
reserves will generally decline as reserves are depleted, except to the extent that we can find, develop or acquire replacement reserves.
One offset to the obvious benefits afforded by higher product prices especially for small to mid-cap companies in this industry, is that
quality domestic oil and gas reserves are hard to find.
 
Approximately
33% and 26% of our total estimated net proved reserves at March 31, 2024 and 2023, respectively, were undeveloped, and those reserves
may not ultimately be developed. 
 
Recovery
of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserve data assumes that we can and will
make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Delays in the development
of our reserves, increases in costs to develop such reserves, or decreases in commodity prices will reduce the future net revenues or
our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, if we or the outside operators
of our properties choose not to spend the capital to develop these reserves, or if we are not able to successfully develop these reserves,
we will be required to write-off these reserves. Any such write-offs of our reserves could reduce our ability to borrow money and could
reduce the value of our common stock.
 
Information
concerning our reserves and future net revenues estimates is inherently uncertain.
 
Estimates
of oil and gas reserves, by necessity, are projections based on engineering data, and there are uncertainties inherent in the interpretation
of such data as well as the projection of future rates of production and the timing of development expenditures. Reserve engineering
is a subjective process of estimating underground accumulations of oil and gas that are difficult to measure. Estimates of economically
recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, such as future
production, oil and gas prices, operating costs, development costs and remedial costs, all of which may vary considerably from actual
results. As a result, estimates of the economically recoverable quantities of oil and gas and of future net cash flows expected therefrom
may vary substantially. As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on a twelve
month un-weighted first-day-of-the-month average oil and gas prices for the twelve months prior to the date of the report. Actual future
prices and costs may be materially higher or lower.
 
An
increase in the differential between NYMEX and the reference or regional index price used to price our oil and gas would reduce our cash
flow from operations.
 
Our
oil and gas is priced in the local markets where it is produced based on local or regional supply and demand factors. The prices we receive
for our oil and gas are typically lower than the relevant benchmark prices, such as The New York Mercantile Exchange (“NYMEX”).
The difference between the benchmark price and the price we receive is called a differential. Numerous factors may influence local pricing,
such as refinery capacity, pipeline capacity and specifications, upsets in the midstream or downstream sectors of the industry, trade
restrictions and governmental regulations. Additionally, insufficient pipeline capacity, lack of demand in any given operating area or
other factors may cause the differential to increase in a particular area compared with other producing areas. During fiscal 2024, differentials
averaged $2.68 per Bbl of oil and ($0.15) per Mcf of gas. Increases in the differential between the benchmark prices for oil and gas
and the wellhead price we receive could significantly reduce our revenues and our cash flow from operations.
 
Drilling
and operating activities are high risk activities that subject us to a variety of factors that we cannot control. 
 
These
factors include availability of workover and drilling rigs, well blowouts, cratering, explosions, fires, formations with abnormal pressures,
pollution, releases of toxic gases and other environmental hazards and risks. Any of these operating hazards could result in substantial
losses to us. In addition, we incur the risk that no commercially productive reservoirs will be encountered, and there is no assurance
that we will recover all or any portion of our investment in wells drilled or re-entered.

 

12
 

 
We
may not be able to fund the capital expenditures that will be required for us to increase reserves and production.
 
We
must make capital expenditures to develop our existing reserves and to acquire new reserves. Historically, we have used our cash flow
from operations and borrowings under our credit facility to fund our capital expenditures, however, lower oil and gas prices may prevent
these options. Volatility in oil and gas prices, the timing of our drilling programs and drilling results will affect our cash flow from
operations. Lower prices and/or lower production will also decrease revenues and cash flow, thus reducing the amount of financial resources
available to meet our capital requirements, including reducing the amount available to pursue our drilling opportunities.
 
The
borrowing base under our credit facility will be determined from time to time by the lender. Reductions in estimates of oil and gas reserves
could result in a reduction in the borrowing base, which would reduce the amount of financial resources available under the credit facility
to meet our capital requirements. Such a reduction could be the result of lower commodity prices and/or production, inability to drill
or unfavorable drilling results, changes in oil and gas reserve engineering, the lender’s inability to agree to an adequate borrowing
base or adverse changes in the lender’s practices regarding estimation of reserves. If cash flow from operations or our borrowing
base decrease for any reason, our ability to undertake exploration and development activities could be adversely affected. As a result,
our ability to replace production may be limited.
 
Our
identified drilling locations are scheduled out over several years, making them susceptible to uncertainties that could materially alter
the occurrence or timing of their drilling.
 
Our
management and outside operators have specifically identified and scheduled drilling locations as an estimation of our future multi-year
drilling activities on our existing acreage. These drilling locations represent a significant part of our growth strategy. Our ability
to drill and develop these locations depends on a number of uncertainties, including crude oil and natural gas prices, the availability
of capital, costs, drilling results, regulatory approvals and other factors. If future drilling results in these projects do not establish
sufficient reserves to achieve an economic return, we may curtail drilling in these projects. Because of these uncertainties, we do not
know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce crude oil
or natural gas from these or any other potential drilling locations.
 
Our
business depends on oil and natural gas transportation facilities which are owned by others.
 
The
marketability of our production depends in part on the availability, proximity and capacity of natural gas gathering systems, pipelines
and processing facilities. Federal and state regulation of oil and gas production and transportation, tax and energy policies, changes
in supply and demand and general economic conditions could all affect our ability to produce and market our oil and gas.
 

We
own non-operating interests in properties developed and operated by third parties and, as a result, we are unable to control the operation
and profitability of such properties. 

 

We participate in the drilling and completion of wells with third-party operators that exercise exclusive control
over such operations. As a participant, we rely on third-party operators to successfully operate these properties pursuant to joint operating
agreements and other similar contractual arrangements. As a participant in these operations, we may not be able to maximize the value
associated with these properties in the manner we believe appropriate, or at all. For example, we cannot control the success of drilling
and development activities on properties operated by third-parties, which depend on a number of factors under the control of a third-party
operator, including such operator’s determinations with respect to, among other things, the nature and timing of drilling and operational
activities, the timing and amount of capital expenditures and the selection of suitable technology. In addition, the third-party operator’s
operational expertise and financial resources and its ability to gain the approval of other participants in drilling wells will impact
the timing and potential success of drilling and development activites in a manner that we are unable to control. A third-party operator’s
failure to adequately perform operations, breach of the applicable agreements or failure to act in ways that are favorable to us could
reduce our production and revenues, negatively impact our liquidity and cause us to spend capital in excess of our current plans, and
have a material adverse effect on our financial condition and results of operations.
 
Acquiring
reserves in the oil and gas industry is highly competitive. 
 
Competition
for oil and gas reserve acquisitions is significant. We may compete with major oil and gas companies, other independent oil and gas companies
and individual producers and operators, some of which have financial and personnel resources substantially in excess of those available
to us. As a result, we may be placed at a competitive disadvantage. Our ability to acquire and develop additional properties in the future
will depend upon our ability to select and acquire suitable producing properties and prospects for future development activities.
 

13
 

 
We
may not be insured against all of the operating hazards to which our business is exposed.
 
Our
operations are subject to all the risks inherent in the exploration for, and development and production of oil and gas including blowouts,
fires and other casualties. We maintain insurance coverage customary for operations of a similar nature, but losses could arise from
uninsured risks or in amounts in excess of existing insurance coverage.
 

Our
effective tax rate may change in the future, which could adversely impact us.
 


The
Tax Cuts and Jobs Act of 2017 (“TCJA”) significantly changed the U.S. federal income taxation of U.S. corporations, including
by reducing the U.S. corporate tax rate, limiting interest deductions and certain deductions for executive compensation, permitting immediate
expensing of certain capital expenditures, and revising the rules governing net operating losses. The TCJA remains unclear in some respects
and continues to be subject to potential amendments and technical corrections. The U.S. Treasury Department and the IRS have issued significant
guidance since the TCJA was enacted, interpreting the TCJA and clarifying some the uncertainties, and are continuing to issue new guidance.
There are still significant aspects of the TCJA for which further guidance is expected, and both the timing and contents of any such
future guidance are uncertain.
 
Further,
changes to the U.S. federal income tax laws are proposed regularly and there can be no assurance that, if enacted, any such changes would
not have an adverse impact on us. For example, President Biden has suggested the reversal or modification of some portions of the TCJA
and certain of these proposals, if enacted, could increase our effective tax rate. There can be no assurance that any such proposed changes
will be introduced as legislation or, if introduced, later enacted and, if enacted, what form such enacted legislation would take. Such
changes could potentially have retroactive effect. In light of these factors, there can be no assurance that our effective tax rate will
not change in future periods. If the effective tax rates were to increase as a result of the future legislation, our business could be
adversely affected.
 
Our
reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our
business, financial condition or reputation.
 
The
oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production,
and processing activities, including digital technologies to interpret seismic data, manage drilling rigs, production equipment and gathering
systems, conduct reservoir modeling and reserves estimation, and process and record financial and operating data. At the same time, cyber
incidents, including deliberate attacks or unintentional events, have increased. The U.S. government has issued public warnings that
indicate energy assets might be specific targets of cyber security threats. Our and our operators’ technologies, systems, networks,
and those of vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that
could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or
other disruption of business activities. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended
period. Our systems for protecting against cyber security risks may not be sufficient. As cyber incidents continue to evolve, we may
be required to expend additional resources to continue to modify or enhance our protective measures or to investigate and remediate any
vulnerability to cyber incidents.
 
The
loss of our chief executive officer or president could adversely impact our ability to execute our business strategy. 
 
We
depend, and will continue to depend in the foreseeable future, upon the continued services of our Chief Executive Officer, Nicholas C.
Taylor and our President and Chief Financial Officer, Tamala L. McComic, who have extensive experience and expertise in evaluating and
analyzing producing oil and gas properties and drilling prospects, maximizing production from oil and gas properties and developing and
executing acquisitions and financing. As of March 31, 2024, we do not have key-man insurance on the lives of Mr. Taylor and Ms. McComic.
The unexpected loss of the services of one or more of these individuals could, therefore, significantly and adversely affect our operations.
 
We
may be affected by one substantial shareholder.
 
Nicholas
C. Taylor beneficially owns approximately 45% of the outstanding shares of our common stock. Mr. Taylor is also our Chairman of the Board
and Chief Executive Officer. As a result, Mr. Taylor has significant influence in matters voted on by our shareholders, including the
election of our Board members. Mr. Taylor participates in all facets of our business and has a significant impact on both our business
strategy and daily operations. The retirement, incapacity or death of Mr. Taylor, or any change in the power to vote shares beneficially
owned by Mr. Taylor, could result in negative market or industry perception and could have an adverse effect on our business.
 


14
 

 
RISKS
RELATED TO OUR COMMON STOCK
 
We
may issue additional shares of common stock in the future, which could cause dilution to all shareholders.
 
We
may seek to raise additional equity capital in the future. Any issuance of additional shares of our common stock will dilute the percentage
ownership interest of all shareholders and may dilute the book value per share of our common stock.
 
Control
by our executive officers and directors may limit your ability to influence the outcome of matters requiring stockholder approval and
could discourage our potential acquisition by third parties. 
 
As
of March 31, 2024, our executive officers and directors beneficially owned approximately 48% of our common stock. These stockholders,
if acting together, would be able to influence significantly all matters requiring approval by our stockholders, including the election
of our board of directors and the approval of mergers or other business combination transactions.
 
The
price of our common stock has been volatile and could continue to fluctuate substantially.
 
Mexco
common stock is traded on the New York Stock Exchange’s NYSE American. The market price of our common stock has and could continue
to experience volatility due to reasons unrelated to our operating performance. These reasons include: supply and demand for oil and
natural gas; political conditions in oil and natural gas producing regions; demand for our common stock and limited trading volume; investor
perception of our industry; fluctuations in commodity prices; variations in our results of operations; legislative or regulatory changes;
general trends in the oil and natural gas industry; market conditions and analysts’ estimates; and, other events in the oil and
gas industry.
 
Many
of these factors are beyond our control, and we cannot predict their potential effects on the price of our common stock. We cannot assure
you that the market price of our common stock will not fluctuate or decline significantly in the future. In addition, the stock markets
in general can experience considerable price and volume fluctuations.
 





ITEM
1B.

UNRESOLVED STAFF COMMENTS

 
None.
 



ITEM
  1C.
CYBERSECURITY

 
Mexco
maintains a cybersecurity program that aims to protect the confidentiality, integrity, and availability of data required by our business
to be stored, analyzed, transported, and/or processed. We have implemented various internal and external controls and processes, including
internal risk assessment and policy implementation, to incorporate a risk-based cybersecurity framework to monitor and mitigate security
threats and other strategies to increase security for our information, facilities, and infrastructure.
 
Risk
Management and Strategy. Mexco recognizes the risk that cybersecurity threats pose to our operations, and cybersecurity is an
important component of our overall risk management strategy. Mexco’s cybersecurity team consists of our executive officers and
third-party cybersecurity personnel. The third-party cybersecurity team, led by professionals with cybersecurity expertise across multiple
industries, takes a cross-functional approach to addressing these risks and engages in discussions with our executive management team
on an as-needed basis.
 
We
have implemented a monitoring and detection system to help promptly identify cybersecurity incidents. We also require our employees to
receive annual cybersecurity awareness training. We perform cybersecurity tabletop exercises to test the effectiveness of our incidence
response plan (“IRP”) and implement post-incident “lessons learned” to enhance our response. We provide our system
users with access consistent with the principle of least privilege, which requires that such users be given no more access than necessary
to complete their job functions. We have programs in place to monitor our retained data with the goal of identifying personal identifiable
information and taking appropriate actions to secure the data.
 


15
 

 
We
have an IRP that delineates the procedures to be followed for handling a variety of cybersecurity incidents; categorizes potential cybersecurity
incidents and the required timeframe for reporting each; establishes cybersecurity incident response levels; provides for investigations
designed to help us to meet applicable legal obligations, including possible notification requirements; and outlines the roles and responsibilities
for various personnel in the event of a cybersecurity incident.
 
Governance.
The Board, in coordination with the Audit Committee and Chief Financial Officer, is responsible for the oversight of risks from
cybersecurity threats. The responsibilities of the Audit Committee include overseeing policies and management systems for cybersecurity
matters and reviewing Mexco’s strategy, objectives, and policies relative to cybersecurity. In addition, the Board and the Audit
Committee receive regular presentations and reports on cybersecurity risks that address a range of topics, including developments, technological
trends or tools, third party updates, and regulatory standards. Our IRP calls for prompt and timely direct notifications and updates
to the Board (or its committees) as necessary in connection with cybersecurity incidents deemed to have a moderate or higher business
impact, even if immaterial. On a periodic basis, the Board and the Audit Committee discuss our approach to cybersecurity with our executive
officers and cybersecurity personnel.
 
Management
plays a role in assessing and managing our material risks from cybersecurity threats through membership on our cybersecurity team, as
well as by making final materiality determinations and disclosures and other compliance decisions, as reflected in our IRP.
 
Impact
of Risks from Cybersecurity Threats. As of the date of this Report, we are not aware of any previous cybersecurity threats that
have materially affected, or are reasonably likely to materially affect, the Company, including our business strategy, results of operations
or financial condition. Notwithstanding the approach we take to cybersecurity, we may not be successful in preventing or mitigating a
cybersecurity incident that could have a material adverse effect on us.
 
For
more information on our cybersecurity related risks, see “Item 1A. Risk Factors” above for additional information.
 



ITEM
  2.

  PROPERTIES 

 
Our
properties consist primarily of oil and gas wells and our ownership in leasehold acreage, both developed and undeveloped. As of March
31, 2024, we had interests in approximately 6,800 gross (25.7 net) producing oil and gas wells and owned leasehold mineral, royalty and
other interests in approximately 579,000 gross (2,709 net) acres.
 
Oil
and Natural Gas Reserves
 
In
accordance with current SEC rules, the average prices used in computing reserves at March 31, 2024 were $76.88 per bbl of oil compared
to $92.02 in 2023, a decrease of 16%, and $2.75 per mcf of natural gas compared to $5.68 in 2023, a decrease of 52%, such prices are
based on the 12-month unweighted arithmetic average market prices for sales of oil and natural gas on the first calendar day of each
month during fiscal 2024. The benchmark price of $73.96 per bbl of oil at March 31, 2024 versus $87.45 at March 31, 2023, was adjusted
by lease for gravity, transportation fees and market differentials and did not give effect to derivative transactions. The benchmark
price of $2.45 per mcf of natural gas at March 31, 2024 versus $5.96 at March 31, 2023, was adjusted by lease for BTU content, transportation
fees and market differentials.
 
For
information concerning our costs incurred for oil and gas operations, net revenues from oil and gas production, estimated future net
revenues attributable to our oil and gas reserves, present value of future net revenues discounted at 10% and changes therein, see Notes
to the Company’s consolidated financial statements.
 

16
 

 
Proved
reserves are estimated reserves of crude oil (including condensate and natural gas liquids) and natural gas that geological and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating
conditions. Proved developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved
undeveloped reserves are proved reserves that are expected to be recovered from new wells drilled to known reservoirs on undrilled acreage
for which the existence and recoverability of such reserves can be estimated with reasonable certainty, or from existing wells on which
a relatively major expenditure is required to establish production.
 
The
engineering report with respect to Mexco’s estimates of proved oil and gas reserves as of March 31, 2024 and 2023 is based on evaluations
prepared by Russell K. Hall and Associates, Inc. Environmental Engineering Consultants, based in Midland, Texas (“Hall and Associates”),
a summary of which is filed as Exhibit 99.1 to this annual report.
 
Management
maintains internal controls designed to provide reasonable assurance that the estimates of proved reserves are computed and reported
in accordance with rules and regulations provided by the SEC. As stated above, Mexco retained Hall and Associates to prepare estimates
of our oil and gas reserves. Management works closely with this firm, and is responsible for providing accurate operating and technical
data to it. Our Chief Financial Officer who has over 26 years experience in the oil and gas industry reviews the final reserves estimate
and consults with a degreed geological consultant with extensive geological experience and if necessary, discusses the process used and
findings with Alan Neal, the technical person at Hall and Associates responsible for evaluating the proved reserves covered by this report.
Mr. Neal is a member of the Society of Petroleum Engineers and has over 36 years of experience in the oil and gas industry. Our Chairman
and Chief Executive Officer who has over 46 years of experience in the oil and gas industry also reviews the final reserves estimate.
 
Numerous
uncertainties exist in estimating quantities of proved reserves. Reserve estimates are imprecise and subjective and may change at any
time as additional information becomes available. Furthermore, estimates of oil and gas reserves are projections based on engineering
data. There are uncertainties inherent in the interpretation of this data as well as the projection of future rates of production. The
accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. Actual
future production, oil and gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil
and gas reserves will most likely vary from the assumptions and estimates. Any significant variance could materially affect the estimated
quantities and value of our oil and gas reserves, which in turn may adversely affect our cash flow, results of operations and the availability
of capital resources.
 
Per
the current SEC rules, the prices used to calculate our proved reserves and the present value of proved reserves set forth herein are
made using the 12-month unweighted arithmetic average of the first-day-of-the-month price. All prices are held constant throughout the
life of the properties. Actual future prices and costs may be materially higher or lower than those as of the date of the estimate. The
timing of both the production and the expenses with respect to the development and production of oil and gas properties will affect the
timing of future net cash flows from proved reserves and their present value. Except to the extent that we acquire additional properties
containing proved reserves or conduct successful exploration and development activities, or both, our proved reserves will decline as
reserves are produced.
 

17
 

 
Our
estimated proved oil and gas reserves and present value of estimated future net revenues from proved oil and gas reserves in the periods
ended March 31 are summarized below.
 
PROVED
RESERVES 
 


  
March 31, 

  
2024  
2023 

Oil (Bbls): 
    
   

Proved developed – Producing 
 394,000  
 451,000 

Proved developed – Non-producing 
 50,620  
 35,770 

Proved undeveloped 
 346,330  
 240,060 

Total 
 790,950  
 726,830 

Natural gas (Mcf): 
    
   

Proved developed – Producing 
 3,346,460  
 3,826,370 

Proved developed – Non-producing 
 219,780  
 145,000 

Proved undeveloped 
 970,880  
 978,010 

Total 
 4,537,120  
 4,949,380 

  
    
   

Total net proved reserves (BOE) (1) 
 1,547,127  
 1,551,725 

  
    
   

PV-10 Value (2) 
$29,078,000  
$39,473,000 

Present value of future income tax discounted at 10% 
 (4,450,000) 
 (6,658,000)

Standardized measure of discounted future net cash flows (3) 
$24,628,000  
$32,815,000 

  
    
   

Prices used in Calculating Reserves: (4) 
    
   

Natural gas (per Mcf) 
$2.75  
$5.68 

Oil (per Bbl) 
$76.88  
$92.02 

 



(1)
These
    reserve estimates do not include the Company’s interest in two LLCs referred to in Item 1. Business – Company Profile
    on page 4 hereto. The first LLC has returned $276,098 and 92% of the total investment since inception in fiscal 2020. 

(2)
The
    PV-10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted
    at 10% per annum, which is the most directly comparable GAAP financial measure. PV-10 is relevant and useful to investors because
    it presents the discounted future net cash flows attributable to our estimated net proved reserves prior to taking into account future
    corporate income taxes. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our
    reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural
    gas properties. Our reconciliation of this non-GAAP financial measure is shown in the table as the PV-10, less future income taxes,
    discounted at 10% per annum, resulting in the standardized measure of discounted future net cash flows. The standardized measure
    of discounted future net cash flows represents the present value of future cash flows attributable to our proved oil and natural
    gas reserves after income tax, discounted at 10%. 

(3)
In
    accordance with SEC requirement, the standardized measure of discounted future net cash flows was computed by applying 12-month first
    day of the month average prices for oil and gas during the fiscal year to the estimated future production of proved oil and gas reserves,
    less estimated future expenditures (based on year-end costs) to be incurred in developing and producing the proved reserves, less
    estimated future income tax expenses (based on year-end statutory tax rates, with consideration of future tax rates already legislated)
    to be incurred on pretax net cash flows less tax basis of the properties and available credits, and assuming continuation of existing
    economic conditions. 

(4)
These
    prices reflect adjustment by lease for quality, transportation fees and market differentials. 

 
During
fiscal 2024, we added proved reserves of 272 thousand BOE (“MBOE”) through extensions and discoveries, added 44 MBOE through
acquisitions, subtracted 163 MBOE for downward revisions of previous estimates. Such downward revisions are primarily attributable to
a decrease in crude oil and natural gas prices and partially the result of reserves written off due to the five-year limitation and the
change in the timing of new development. The reserves written off were primarily royalty interests on leases in DeSoto Parish, Louisiana and Karnes County,
Texas which are held by production and still in place to be developed in the future.
 
During
the fiscal year ending March 31, 2024, we had a working or royalty interest in the development of 43 wells converting reserves of approximately
62,000 BOE from proved undeveloped to proved developed – producing with capital cost of approximately $940,000.
 
Oil
and gas prices significantly impact the calculation of the PV-10 and the standardized measure of discounted future net cash flows. The
present value of future net cash flows does not purport to be an estimate of the fair market value of the Company’s proved reserves.
An estimate of fair value would also take into account, among other things, anticipated changes in future prices and costs, the expected
recovery of reserves in excess of proved reserves and a discount factor more representative of the time value of money and the risks
inherent in producing oil and gas. Future prices received for production and costs may vary, perhaps significantly, from the prices and
costs assumed for purposes of these estimates. The 10% discount factor used to calculate present value, which is required by Financial
Accounting Standards Board (“FASB”) Accounting Standard Codification (“ASC”) 932, “Extractive Activities
– Oil and Gas”, may not necessarily be the most appropriate discount rate. The present value, no matter what discount rate
is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.
 
We
have not filed any other oil or gas reserve estimates or included any such estimates in reports to other federal or foreign governmental
authority or agency during the year ended March 31, 2024, and no major discovery is believed to have caused a significant change in our
estimates of proved reserves since that date.
 


18
 

 
Drilling
Activities
 

The
following table sets forth our drilling activity in wells in which we own a working interest for the years ended March 31:
 




  
Year Ended March 31, 

  
2024  
2023 

  
Gross  
Net  
Gross  
Net 

Exploratory Wells 
    
    
    
   

Beginning wells in progress 
 -  
 -  
 -  
 - 

Wells spud 
 -  
 -  
 -  
 - 

Successful wells 
 -  
 -  
 -  
 - 

Ending wells in progress 
 -  
 -  
 -  
 - 

  
    
    
    
   

Development Wells 
    
    
    
   

Beginning wells in progress 
 21  
 .05  
 11  
 .04 

Wells spud 
 48  
 .22  
 54  
 .36 

Successful wells 
 (53) 
 (.09) 
 (44) 
 (.35)

Ending wells in progress 
 16  
 .17  
 21  
 .05 

 

The
information contained in the foregoing table should not be considered indicative of future drilling performance, nor should it be assumed
that there is any necessary correlation between the number of productive wells drilled and the amount of oil and gas that may ultimately
be recovered by us.
 
In
addition to the working interests mentioned above, other operators drilled 101 gross wells (.02 net wells) on company-owned minerals
and royalties at no expense to the Company. We expect the production of our mineral interests will increase as operators continue to
drill, complete and develop our acreage. We expect to capitalize on this development, which requires no capital expenditure funding from
us, and believe the anticipated aggregate royalty receipts will enable us to grow our cash flows. A number of the horizontal wells in
which the Company participates involve longer lateral which are more efficient and have greater estimated ultimate recovery.
 
Productive
Wells and Acreage
 
Productive
wells consist of producing wells and wells capable of production, including gas wells awaiting pipeline connections. Wells that are completed
in more than one producing zone are counted as one well. As of March 31, 2024, we held an interest in approximately 6,800 gross (25.7
net) productive wells, including approximately 5,700 wells in which we held an overriding or royalty interest and 1,100 wells in which
we held a working interest.
 
A
gross acre is an acre in which an interest is owned. A net acre is deemed to exist when the sum of fractional ownership interests in
gross acres equals one. The number of net acres is the sum of the fractional interests owned in gross acres. The following table sets
forth the approximate developed acreage in which we held a leasehold mineral or other interest as of March 31, 2024:
 


  
Acreage 

  
Gross  
Net 

Texas 
 373,500  
 1,531 

Oklahoma 
 69,300  
 815 

Louisiana 
 38,900  
 87 

New Mexico 
 31,000  
 184 

North Dakota 
 22,400  
 23 

Ohio 
 20,300  
 1 

Kansas 
 8,500  
 41 

Montana 
 5,000  
 1 

Wyoming 
 3,800  
 5 

Colorado 
 3,000  
 11 

Arkansas 
 1,600  
 5 

Alabama 
 1,000  
 2 

Mississippi 
 600  
 2 

Virginia 
 100  
 1 

Total 
 579,000  
 2,709 

 


19
 

 
Net
Production, Unit Prices and Costs
 
The
following table summarizes our net oil and natural gas production, the average sales price per barrel (“bbl”) of oil and
per thousand cubic feet (“mcf”) of natural gas produced and the average production (lifting) cost per unit of production
for the years ended March 31:
 


  
Years Ended March 31, 

 
2024  
2023 

Oil (a): 
    
   

Production (Bbls) 
 69,999  
 73,968 

Revenue 
$5,348,257  
$6,522,163 

Average Bbls per day (d) 
 192  
 203 

Average sales price per Bbl 
$76.40  
$88.18 

Gas (b): 
    
   

Production (Mcf) 
 502,879  
 534,363 

Revenue 
$1,114,390  
$2,858,460 

Average Mcf per day (d) 
 1,378  
 1,464 

Average sales price per Mcf 
$2.22  
$5.35 

Total BOE (c) 
 153,812  
 163,029 

Production costs: 
    
   

Production expenses: 
$1,029,279  
$1,039,893 

Production expenses per BOE 
$6.69  
$6.38 

Production expenses per sales dollar 
$0.16  
$0.11 

Production and ad valorem taxes: 
$497,193  
$679,826 

Production and ad valorem taxes per BOE 
$3.23  
$4.17 

Production and ad valorem taxes per sales dollar 
$0.08  
$0.07 

Total oil and gas revenue 
$6,462,647  
$9,380,623 

 


 
(a)
Includes
    condensate.

 
(b)
Includes
    natural gas products.

 
(c)
Natural
    gas production is converted to oil production using a ratio of six Mcf to one Bbl of oil. 

 
(d)
Calculated
    on a 365 day year.

 



ITEM 3.
LEGAL PROCEEDINGS

 


We
may, from time to time, be a party to various proceedings and claims incidental to our business. While many of these matters involve
inherent uncertainty, we believe that the amount of the liability, if any, ultimately incurred with respect to these proceedings and
claims will not have a material adverse effect on our consolidated financial position as a whole or on our liquidity, capital resources
or future results of operations.
 


ITEM
4.
 MINE SAFETY DISCLOSURES

 
Not
applicable.
 

20
 

 
PART
II
 


ITEM
5.
 MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED
STOCKHOLDER MATTERS AND ISSUER
PURCHASES OF EQUITY SECURITIES


 
Market
Information
 
In
September 2003, our common stock began trading on the NYSE American, formerly the American Stock Exchange and more recently the NYSE
MKT, under the symbol “MXC”. Prior to September 2003, the Company’s common stock was traded on the over-the-counter
bulletin board market under the symbol “MEXC”. The registrar and transfer agent is Issuer Direct Corporation, 500 Perimeter
Park Drive, Suite D, Morrisville, North Carolina, 27560 (Tel: 877-481-4014). The following table sets forth certain information as to
the high and low sales price quoted for Mexco’s common stock on the NYSE American.
 


  
  
High  
Low 

2024: 
April - June 2023 
$13.84  
$10.30 

  
July - September 2023 
 13.63  
 11.36 

  
October - December 2023 
 13.50  
 9.05 

  
January - March 2024 
 10.49  
 9.02 

  
  
    
   

2023: 
April - June 2022 
$24.18  
$13.79 

  
July - September 2022 
 20.84  
 14.43 

  
October - December 2022 
 18.25  
 12.40 

  
January - March 2023 
 15.39  
 10.50 

 
On
March 31, 2024, the closing sales price of our common stock on the NYSE American was $9.98 per share.
 
Stockholders
 
As
of March 31, 2024, we had 2,226,916 shares issued and 827 shareholders of record which does not include shareholders for whom shares
are held in a “nominee” or “street” name. Of these issued shares, 135,517 are held in the treasury.
 
Dividends
 
As
of March 31, 2023, the Company had never paid a cash dividend to the Company’s shareholders. Payment of dividends are at the discretion
of our Board of Directors after taking into account many factors, including our financial condition, operating results, current and anticipated
cash needs and plans for expansion. In addition, our current bank loan prohibits us from paying cash dividends on our common stock without
written permission.
 
On
April 10, 2023, the Company announced that its Board of Directors declared a special dividend of $0.10 per common share to its shareholders
of record at the close of business on May 1, 2023. The special dividend was paid on May 15, 2023. The Company obtained written permission
from WTNB prior to declaring the special dividend.
 
The
Company can provide no assurance that dividends will be authorized or declared in the future or as to the amount or type of any future
dividends. Our board of directors’ determination with respect to any such dividends, including the record date, the payment date
and the actual amount of the dividend, will depend upon our profitability and financial condition, contractual restrictions, restrictions
imposed by applicable law and other factors that the board deems relevant at the time of such determination.
 
Subsequently,
on April 30, 2024, the Company announced that its Board of Directors declared a regular annual dividend of $0.10 per common share to its shareholders
of record at the close of business on May 21, 2024. The dividend was paid on June 4, 2024. The Company obtained written permission from
WTNB prior to declaring the regular annual dividend.
 
Securities
Authorized for Issuance Under Compensation Plans
 
The
following table includes certain information about our Employee Incentive Stock Plan as of March 31, 2024, which has been approved by
our stockholders.
 


  
Number of Shares Authorized for Issuance under Plan  
Number of Shares to be Issued upon Exercise of Outstanding Options  
Weighted Average Exercise Price of Outstanding Options  
Number of Shares Remaining Available for Future Issuance under Plan 

2009 Plan 
 200,000  
 45,250  
$5.27  
 - 

2019 Plan 
 200,000  
 120,500  
 10.89  
 66,000 

Total 
 400,000  
 165,750  
$9.36  
 66,000 

 
 

21
 

 
Issuer
Repurchases
 
In
March 2023, the Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock for
the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board.
Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions.
The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of
stock, our financial performance and other conditions. Repurchases may also be made from time-to-time in connection with the settlement
of our share-based compensation awards. Repurchases will be funded from cash flow.
 
The
following table provides information related to repurchases of our common stock for the treasury account during the year ended March
31, 2024:
 


  
Total Number of Shares Purchased  
Average Price Paid per Share  
Total Number of Shares Purchased as Part of Publicly Announced Program  
Approximate Dollar Value of Shares that May Yet be Purchased Under the Program 

July 1-31, 2023 
 9,500  
$12.28  
 9,500  
$883,293 

August 1-31, 2023 
 9,500  
$12.69  
 9,500  
$762,742 

September 1-30, 2023 
 7,000  
$12.57  
 7,000  
$674,744 

October 1-31, 2023 
 6,000  
$12.58  
 6,000  
$599,267 

November 1-30, 2023 
 1,839  
$11.49  
 1,839  
$578,141 

December 1-31, 2023 
 3,322  
$10.02  
 3,322  
$544,867 

January 1-31, 2024 
 1,501  
$10.01  
 1,501  
$529,849 

February 1-28, 2024 
 4,266  
$9.98  
 4,266  
$487,288 

March 1-31, 2024 
 7,173  
$10.08  
 7,173  
$414,965 

Total 
 50,101  
$ 11.68  
 50,101  
   

 
During
the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $585,035, an average
price of $11.68 per share. During the year ended March 31, 2023, the Company repurchased 18,416 shares for the treasury account at an
aggregate cost of $244,494, an average price of $13.28 per share.
 
Subsequently,
in April 2024, the Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s
common stock, par value, $0.50, for the treasury account. This authorization replaced the previously authorized $1,000,000 common stock
repurchase program which had $414,965 remaining at the time it was replaced.
 
Also
in April 2024, the Company repurchased 13,766 shares for the treasury account at an aggregate cost of $188,637, an average price of $13.70
per share.
 
On
August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other
tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases
after December 31, 2022. The IRA 2022 does provide for certain exceptions for repurchases of stock including an exception as long as
the aggregate value of the repurchases for the tax year does not exceed $1,000,000.

 



ITEM 6.
RESERVED 


 

22
 

 


ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS

 
The
following discussion is intended to provide information relevant to an understanding of our financial condition, changes in our financial
condition and our results of operations and cash flows and should be read in conjunction with our consolidated financial statements and
notes thereto included elsewhere in this Form 10-K.
 

Liquidity
and Capital Resources and Commitments
 
Historically,
we have funded our operations, acquisitions, exploration and development expenditures from cash generated by operating activities, bank
borrowings, sales of non-core properties and issuance of common stock. Our primary financial resource is our base of oil and gas reserves.
We have pledged our producing oil and gas properties to secure our credit facility. We do not have any delivery commitments to provide
a fixed and determinable quantity of our oil and gas under any existing contract or agreement.
 
Our
long-term strategy is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and
developing oil and gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and
working interests and non-operated properties in areas with significant development potential.
 
Cash
Flows
 
Changes
in the net funds provided by or (used in) each of our operating, investing and financing activities are set forth in the table below:
 


  
For the Years Ended March 31,  
  

  
2024  
2023  
Change 

Net cash provided by operating activities 
$4,433,935  
$6,515,895  
$(2,081,960)

Net cash used in investing activities 
$(3,416,499) 
$(5,441,075) 
$(2,024,576)

Net cash used in financing activities 
$(779,723) 
$(209,815) 
$569,908 

 
Cash
Flow Provided by Operating Activities. Cash flow from operating activities is primarily derived from the production of our crude
oil and natural gas reserves and changes in the balances of non-cash accounts, receivables, payables or other non-energy property asset
account balances. Cash flow provided by our operating activities for the year ended March 31, 2024 was $4,433,935 in comparison to $6,515,895
for the year ended March 31, 2023. This decrease of $2,081,960 in our cash flow operating activities consisted of increase in our non-cash
expenses of $505,448; a decrease in our accounts receivable of $426,598; an increase of $49,673 of our accounts payable and accrued expenses;
and, a decrease in our net income for the current year of $3,317,518. Variations in cash flow from operating activities may impact our
level of exploration and development expenditures.
 
Our
expenditures in operating activities consist primarily of production expenses and engineering services. Our expenses also consist of
employee compensation, accounting, insurance and other general and administrative expenses that we have incurred in order to address
normal and necessary business activities of a public company in the crude oil and natural gas production industry.
 
Cash
Flow Used in Investing Activities. Cash flow from investing activities is derived from changes in oil and gas property balances.
For the year ended March 31, 2024, we had net cash of $3,016,499 used for additions to oil and gas properties and a $400,000 investment
in two limited liability companies compared to $5,014,357 and $425,000, respectively, for the year ended March 31, 2023.
 
Cash
Flow Used in Financing Activities. Cash flow from financing activities is derived from our changes in long-term debt and in
equity account balances. Net cash flow used in our financing activities was $779,723 for the year ended March 31, 2024 compared to
net cash flow used in our financing activities of $209,815 for the year ended March 31, 2023. During the year ended March 31, 2024,
we expended $213,600 to pay the annual dividend, expended $585,035 to purchase 50,101 shares of our stock for the treasury account,
and received proceeds of $19,662 for the exercise of employee and director stock options. During the year ended March 31, 2023, we received proceeds of $16,700 from the exercise of director stock options, received payment of $30,179 from a director for profits on
purchase of stock within the six-month window of a previous stock sale, expended $244,494 for the purchase of 18,416 shares of our
stock for the treasury and, expended $12,200 for the renewal of our credit facility.
 
Accordingly,
net cash increased $237,713, leaving cash and cash equivalents on hand of $2,473,484 as of March 31, 2024.
 

23
 

 
We
had working capital of $3,259,200 as of March 31, 2024 compared to working capital of $3,475,776 as of March 31, 2023, a decrease of
$216,576 for the reasons set forth below.
 
Oil
and Natural Gas Property Development. 
 
New
Participations in Fiscal 2024. The Company participated in the drilling and completion of 51 horizontal wells and 1 vertical well
at a cost of approximately $2,300,000, of which $2,000,000 was expended during the fiscal year ending March 31, 2024. Nineteen of these
wells have not been completed. Forty-eight of these horizontal wells are in the Delaware Basin located in the western portion of the
Permian Basin in Lea and Eddy Counties, New Mexico. The remaining three horizontal wells are in the Bakken formation in McKenzie County,
North Dakota and the vertical well is in Irion County, Texas.
 
In
addition to the above working interests, there were 101 gross wells (.025 net wells) drilled by other operators on Mexco’s royalty
interests and 348 gross wells (7.65 net wells) obtained through acquisitions.
 
Mexco
expended approximately $264,000 to participate in the drilling of four horizontal wells in the Wolfcamp Sand formation of the Delaware
Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .52%. Two of these wells began producing in November
2023 and the other two in March 2024 with initial average production rates of 822 barrels of oil, 4,159 barrels of water and 2,574,000
cubic feet of gas per day, or 1,251 barrels of oil equivalent (“BOE”) per day.
 
Mexco
expended approximately $152,000 to participate in the drilling of two horizontal wells in the Penn Shale formation of the Delaware Basin
in Lea County, New Mexico. Mexco’s working interest in these wells is .4%. These wells began producing in November 2023 with initial
average production rates of 837 barrels of oil, 1,794 barrels of water and 659,000 cubic feet of gas per day, or 947 BOE per day.
 
Mexco
expended approximately $105,000 to participate in the drilling and completion of two horizontal wells in the Penn Shale formation of
the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .285%. These wells began
producing in September 2023 with initial average production rates of 582 barrels of oil, 1,488 barrels of water and 791,000 cubic feet
of gas per day, or 714 BOE per day.
 
Mexco
expended approximately $870,000 to participate in the drilling of five horizontal wells in the Bone Spring Sand formation of the Delaware
Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately 1.16%. Subsequently, in April 2024, two
of these wells were completed with initial average production rates of 1,065 barrels of oil, 2,107 barrels of water and 706,500 cubic
feet of gas per day, or 1,183 BOE per day.
 
In
July 2023, Mexco expended approximately $36,000 to participate in the drilling and completion of two horizontal wells in the Bone Spring
Sand formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is approximately .1%. These
wells began producing in September 2023 with initial average production rates of 898 barrels of oil, 1,969 barrels of water and 503,000
cubic feet of gas per day, or 982 BOE per day.
 
In
November 2023, Mexco expended approximately $32,000 to participate in the drilling and completion of one horizontal well in the Penn
Shale formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in this well is .165%.
 
In
February 2024, Mexco expended approximately $74,000 to participate in the drilling of two horizontal wells in the Bone Spring Sand formation
of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .53%. Subsequently, in May 2024, Mexco
expended approximately $90,000 to complete these wells.
 
In
February 2024, Mexco expended approximately $170,000 to participate in the drilling of four horizontal wells in the Bone Spring Sand
formation of the Delaware Basin in Lea County, New Mexico. Mexco’s working interest in these wells is .45%.
 

24
 

 

In
February 2024, Mexco expended approximately $153,000 to participate in an exploratory well in the Fusselman Formation of Irion County,
Texas. Subsequently, in May 2024, the Company expended $27,000 for additional drilling costs. This well was later determined to be noncommercial
and will be plugged and abandoned in fiscal 2025.
 
In
October 2022, the Company made an approximately 2% equity investment commitment in a limited liability company amounting to $2,000,000
of which $800,000 has been funded as of March 31, 2024. The limited liability company is capitalized at approximately $100 million to
purchase mineral interests in the Utica and Marcellus areas in the state of Ohio. Subsequently, in May 2024, the Company funded another
$200,000 toward this investment. This LLC has returned $81,231 or 8% of the total investment.

 
Completion
of Wells Drilled in Fiscal 2023. The Company expended approximately $450,000 in the completion of 21 horizontal wells in which the
Company participated in fiscal 2023.
 
The
Company expended approximately $427,000 for the completion costs of eight horizontal wells in the Wolfcamp Sand formation of the Delaware
Basin in Lea County, New Mexico that the Company participated in drilling during fiscal 2023. Mexco’s working interest in these
wells is .52%. These wells began producing in October 2023 with initial average production rates of 825 barrels of oil, 3,540 barrels
of water and 2,150,000 cubic feet of gas per day, or, 1,183 BOE per day.
 
Three
horizontal wells in the Bone Spring formation of the Delaware Basin in Eddy County, New Mexico in which the Company participated during
fiscal 2023 were completed in May 2023 with initial average production rates of 437 barrels of oil, 983 barrels of water and 603,000
cubic feet of gas per day, or, 538 barrels of oil equivalent per day. Mexco’s working interest in these wells is .05%.
 
Seven
horizontal wells in the Bone Spring Sand formation of the Delaware Basin in Lea County, New Mexico in which the Company participated
during fiscal 2023 were completed with initial average production rates of 1,827 barrels of oil, 1,945 barrels of water and 2,264,000
cubic feet of gas per day, or, 2,204 barrels of oil equivalent per day. Mexco’s working interest in these wells is .033%.
 
Acquisitions.
During the year, the Company acquired royalty interests in 39 producing wells with additional potential locations for development
in Howard and Lee Counties, Texas for an aggregate purchase price of $261,700.
 
In
February 2024, the Company acquired royalty interests in 8 producing wells with additional potential locations for development operated
by PDC Energy, Inc. and 4 producing wellbores operated by Chevron Corporation for an aggregate purchase price of $575,600. These wells
are located in Weld County, Colorado.
 
In
February 2024, the Company acquired royalty interests in 255 producing wells in the Haynesville trend area of Caddo Parish, Louisiana
for a purchase price of $390,300.
 
In
December 2023, the Company acquired royalty (mineral) interests in 7 wells operated by Occidental Petroleum Corporation and located in
Reeves County, Texas for a purchase price of $364,000 which is effective November 1, 2023. In January 2024, the Company acquired an additional
interest in these same wells for a purchase price of $91,000, effective December 1, 2023.
 
In
November 2023, the Company acquired small royalty interests in 27 producing wells as well as non-producing mineral interests in 1,280
gross acres located in Crane, Ector, Midland and Upton Counties, Texas for an aggregate purchase price of $105,800.
 
Subsequently,
in April 2024, the Company acquired small royalty (mineral) interests in 21 wells operated by Anadarko Petroleum Corporation and Cimarex
Energy Company and located in Reeves County, Texas for a purchase price of $158,000 which is effective April 1, 2024.
 

25
 

 

Sales
of Properties. During the first quarter of fiscal 2024, the Company received approximately $280,000 in cash from a sale of joint
venture leasehold acreage and marginal producing working interest wells in Reagan County, Texas, marginal producing working interest
wells in Pecos County, Texas and interest in surface acreage in Palo Pinto County, Texas.
 
In
December 2023, the Company made on a 3-year Term Assignment of 98% of the Company’s leasehold interest in certain deep rights of
200 acres in Loving and Ward Counties, Texas. The Company received $5,000 per net leasehold acre in the total amount of approximately
$980,000. The Company retained the remaining 2% leasehold interest as a participating interest in the full unit at approximately .625%
working interest. The Company also retained an overriding royalty interest of 5% proportionately reduced.
 
Also
in December 2023, the Company made on a 3-year Term Assignment of the Company’s leasehold interest in 12.96 net mineral acres located
in Lea County, New Mexico. The Company received $2,500 per net leasehold acre in the total amount of $32,400. The Company retained an
overriding royalty interest equal to the positive difference between 25% and any existing burdens of record as of the effective date.
 
Subsequent
Participations. In April 2024, Mexco expended approximately $80,000 to participate in the drilling of five horizontal wells in the
Bone Spring formation of the Delaware Basin in Lea County, New Mexico and $127,800 to drill four horizontal wells in the Wolfcamp Sand
formation of the Delaware Basin in Lea County, New Mexico.
 
We
are participating in other projects and are reviewing projects in which we may participate. The cost of such projects would be funded,
to the extent possible, from existing cash balances and cash flow from operations. The remainder may be funded through borrowings on
the credit facility and, if appropriate, sales of non-core properties.
 
Markets.
Crude oil and natural gas prices generally remained volatile during the last year. The volatility of the energy markets makes it
extremely difficult to predict future oil and natural gas price movements with any certainty. For example, in the last twelve months,
the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from a low of $63.10 per bbl in June 2023
to a high of $89.66 per bbl in September 2023. The Henry Hub Spot Market Price (“Henry Hub”) for natural gas has ranged from
a low of $1.25 per MMBtu in March 2024 to a high of $3.34 per MMBtu in October 2023.
 
On
March 31, 2024 the WTI posted price for crude oil was $79.15 per bbl and the Henry Hub spot price for natural gas was $1.54 per MMBtu.
See Results of Operations below for realized prices.
 
Results
of Operations
 
Fiscal
2024 Compared to Fiscal 2023
 
We
had net income of $1,344,952 for the year ended March 31, 2024 compared to $4,662,702 for the year ended March 31, 2023, a 71% decrease
as a result of a decrease in operating revenues due to a decrease in oil and natural gas prices and production that is further explained
below.
 
Oil
and natural gas sales. Revenue from oil and natural gas sales was $6,462,647 for the year ended March 31, 2024, a 31% decrease from
$9,380,623 for the year ended March 31, 2023. This resulted from a decrease in oil and natural gas prices and production volumes. The
following table sets forth our oil and natural gas revenues, production quantities and average prices received during the fiscal years
ended March 31:
 


  
2024  
2023  
% Difference 

Oil: 
    
    
   

Revenue 
$5,348,257  
$6,522,163  
 (18.0)%

Volume (bbls) 
 69,999  
 73,968  
 (5.4)%

Average Price (per bbl) 
$76.40  
$88.18  
 (13.4)%

  
    
    
   

Gas: 
    
    
   

Revenue 
$1,114,390  
$2,858,460  
 (61.0)%

Volume (mcf) 
 502,879  
 534,363  
 (5.9)%

Average Price (per mcf) 
$2.22  
$5.35  
 (58.5)%

 

26
 

 
Production
and exploration. Production costs were $1,526,472 in fiscal 2024, an 11% decrease from $1,719,719 in fiscal 2023. This was primarily
the result of a decrease in production taxes as a result of the decrease in oil and gas revenues.
 
Depreciation,
depletion and amortization. Depreciation, depletion and amortization (“DD&A”) expense was $1,969,742 in fiscal 2024,
a 6% increase from $1,854,047 in fiscal 2023. This was primarily due to an increase in the full cost pool amortization and a decrease
in the oil and gas reserves partially offset by a decrease in oil and gas production.
 
General
and administrative expenses. General and administrative expenses were $1,243,548 for the year ended March 31, 2024, an 11% increase
from $1,120,691 for the year ended March 31, 2023. This was primarily due to an increase in employee stock option compensation, salaries
and contract services, and accounting fees.
 
Interest
expense. Interest expense was $5,234 in fiscal 2024, a 60% decrease from $13,097 in fiscal 2023, due to a decrease in borrowings.
 
Income
taxes. Federal income tax for fiscal 2024 was $500,915. There was no federal income tax for fiscal 2023 because the Company was
in a net deferred tax asset position. State income tax was $119,629 in fiscal 2024, a 27% decrease from $164,510 for fiscal 2023 due
to the decrease in oil and natural gas sales in the State of New Mexico. The effective tax rate for state and federal taxes combined
for fiscal 2024 and fiscal 2023 was 32% and 3%, respectively. The increase in the effective federal tax rate is the result of the
Company now being in a net deferred tax liability position and the reconciliation to the federal tax return.
 
Contractual
Obligations
 
We
have no off-balance sheet debt or unrecorded obligations and have not guaranteed the debt of any other party. The following table summarizes
future payments we are obligated to make based on agreements in place as of March 31, 2024:
 


  
Payments due in: 

  
Total  
less than 1 year  
1 - 3 years  
over 3 years 

Contractual obligations: 
    
    
    
   

Leases (1) 
$19,413  
$19,413  
 -  
$- 

 


 
(1)
The lease amount represents the monthly rent amount for our
principal office space in Midland, Texas under a 38-month lease agreement effective May 15, 2018 and extended another 36 months to July
31, 2024. Of this total obligation for the remainder of the lease, our majority shareholder will pay $5,191 less than 1 year for his
portion of the shared office space.

 
Alternative
Capital Resources
 
Although
we have primarily used cash from operating activities, the sales of assets and funding from the credit facility as our primary capital
resources, we have in the past, and could in the future, use alternative capital resources. These could include joint ventures, carried
working interests and issuances of our common stock through a private placement or public offering.
 
Other
Matters
 
Critical
Accounting Policies and Estimates
 
In
preparing financial statements, management makes informed judgments, estimates and assumptions that affect the reported amounts of assets
and liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting
period. On an ongoing basis, management reviews its estimates, including those related to litigation, environmental liabilities, income
taxes, fair value and determination of proved reserves. Changes in facts and circumstances may result in revised estimates and actual
results may differ from these estimates.
 
The
following represents those policies that management believes are particularly important to the financial statements and that require
the use of estimates and assumptions to describe matters that are inherently uncertain.
 

27
 

 
Full
Cost Method of Accounting for Crude Oil and Natural Gas Activities. SEC Regulation S-X defines the financial accounting and reporting
standards for companies engaged in crude oil and natural gas activities. Two methods are prescribed: the successful efforts method and
the full cost method. We have chosen to follow the full cost method under which all costs associated with property acquisition, exploration
and development are capitalized. We also capitalize internal costs that can be directly identified with acquisition, exploration and
development activities and do not include any costs related to production, general corporate overhead or similar activities. The carrying
amount of oil and gas properties also includes estimated asset retirement costs recorded based on the fair value of the asset retirement
obligation (“ARO”) when incurred.
 
Gain
or loss on the sale or other disposition of oil and gas properties is not recognized, unless the sale would significantly alter the relationship
between capitalized costs and proved reserves of oil and natural gas attributable to a country. Under the successful efforts method,
geological and geophysical costs and costs of carrying and retaining undeveloped properties are charged to expense as incurred. Costs
of drilling exploratory wells that do not result in proved reserves are charged to expense. Depreciation, depletion, amortization and
impairment of crude oil and natural gas properties are generally calculated on a well by well or lease or field basis versus the “full
cost” pool basis. Additionally, gain or loss is generally recognized on all sales of crude oil and natural gas properties under
the successful efforts method. As a result our financial statements will differ from companies that apply the successful efforts method
since we will generally reflect a higher level of capitalized costs as well as a higher DD&A rate on our crude oil and natural gas
properties.
 
At
the time it was adopted, management believed that the full cost method would be preferable, as earnings tend to be less volatile than
under the successful efforts method. However, the full cost method makes us more susceptible to significant non-cash charges during times
of volatile commodity prices because the full cost pool may be impaired when prices are low. These charges are not recoverable when prices
return to higher levels. Our crude oil and natural gas reserves have a relatively long life. However, temporary drops in commodity prices
can have a material impact on our business including impact from the full cost method of accounting.
 
Ceiling
Test. Companies that use the full cost method of accounting for oil and gas exploration and development activities are required to
perform a ceiling test each quarter. The full cost ceiling test is an impairment test to determine a limit, or ceiling, on the book value
of oil and gas properties. That limit is basically the after-tax present value of the future net cash flows from proved crude oil and
natural gas reserves plus the lower of cost or fair market value of unproved properties. If net capitalized costs of crude oil and natural
gas properties exceed the ceiling limit, we must charge the amount of the excess to earnings. This is called a “ceiling limitation
write-down.” This impairment to our oil and gas properties does not impact cash flow from operating activities, but does reduce
our stockholders’ equity and reported earnings.
 
The
risk that we will be required to write down the carrying value of crude oil and natural gas properties increases when crude oil and natural
gas prices are depressed or volatile. In addition, write-downs may occur if we experience substantial downward adjustments to our estimated
proved reserves or if purchasers cancel long-term contracts for natural gas production. An expense recorded in one period may not be
reversed in a subsequent period even though higher crude oil and natural gas prices may have increased the ceiling applicable to the
subsequent period.
 
Estimates
of our proved reserves are based on the quantities of oil and gas that engineering and geological analysis demonstrates, with reasonable
certainty, to be recoverable from established reservoirs in the future under current operating and economic parameters. Our reserve estimates
and the projected cash flows are derived from these reserve estimates, in accordance with SEC guidelines by an independent engineering
firm based in part on data provided by us. The accuracy of a reserve estimate is a function of the quality and quantity of available
data, the interpretation of that data, the accuracy of various mandated economic assumptions, and the judgment of the persons preparing
the estimate. Estimates prepared by other third parties may be higher or lower than those included herein. Because these estimates depend
on many assumptions, all of which may substantially differ from future actual results, reserve estimates will be different from the quantities
of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate
may justify material revisions to the estimate.
 
It
should not be assumed that the present value of future net cash flows is the current market value of our estimated proved reserves. In
accordance with SEC requirements, the cost ceiling represents the present value (discounted at 10%) of net cash flows from sales of future
production using the average price over the prior 12-month period.
 
The
estimates of proved reserves materially impact DD&A expense. If the estimates of proved reserves decline, the rate at which we record
DD&A expense will increase, reducing future net income. Such a decline may result from lower market prices, which may make it uneconomic
to drill for and produce higher cost projects.
 

28
 

 
Use
of Estimates. In preparing financial statements in conformity with accounting principles generally accepted in the United States
of America, management is required to make informed judgments, estimates and assumptions that affect the reported amounts of assets and
liabilities as of the date of the financial statements and affect the reported amounts of revenues and expenses during the reporting
period. In addition, significant estimates are used in determining year end proved oil and gas reserves. Although management believes
its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate of our oil and
natural gas reserves, which is used to compute DD&A and impairment of oil and gas properties, is the most significant of the estimates
and assumptions that affect these reported results.
 
Excluded
Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments
in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined
that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of
any impairment is transferred to the capitalized costs being amortized (the DD&A pool). Impairments transferred to the DD&A pool
increase the DD&A rate.
 
Revenue
Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded
under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue
checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received
by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received
historically have not been significant.
 
Asset
Retirement Obligations. The estimated costs of plugging, restoration and removal of facilities are accrued. The fair value of a liability
for an asset’s retirement obligation is recorded in the period in which it is incurred and the corresponding cost capitalized by
increasing the carrying amount of the related long-lived asset. The liability is accreted to its then present value each period, and
the capitalized cost is depreciated by the units of production method. If the liability is settled for an amount other than the recorded
amount, a gain or loss is recognized. For all periods presented, we have included estimated future costs of abandonment and dismantlement
in the full cost amortization base and amortize these costs as a component of our depletion expense.
 
Gas
Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability
is recorded when our excess takes of natural gas volumes exceed our estimated remaining recoverable reserves (over produced). No receivables
are recorded for those wells where Mexco has taken less than its ownership share of gas production (under produced).
 
Stock-based
Compensation. We use the Binomial option pricing model to estimate the fair value of stock-based compensation expenses at grant date.
This expense is recognized as compensation expense in our financial statements over the vesting period. We recognize the fair value of
stock-based compensation awards as wages in the Consolidated Statements of Operations based on a graded-vesting schedule over the vesting
period.
 
Accounts
Receivable. Our accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit is
extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts receivable
under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is completed. The
collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit losses is
determined based on a number of factors, including the length of time accounts receivable are past due, the Company’s previous
loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and
the industry as a whole.
 
Income
Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the
carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted
tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities
of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded
as interest expense and general and administrative expense, respectively.
 

29
 

 
Other
Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based
on estimated useful lives of three to ten years.
 
Investments.
The Company accounts for investments of less than 3% of any limited liability companies at cost. The Company has no control of the
limited liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from
the investment is received, it is immediately recognized on the consolidated statements of operations.
 
Reclassifications.
Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s
presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
 
Leases.
The Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset,
operating lease liability, current, and operating lease liability, long-term on the consolidated balance sheets.
 
Operating
lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent
its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement
date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate,
the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value
of lease payments. The incremental borrowing rate used at adoption was 3.75%. Significant judgement is required when determining the
incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
 
Recent
Accounting Pronouncements. In December 2023, the FASB issued Accounting Standards Update (“ASU”) No. 2023-09, “Income
Taxes (Topic 740): Improvements to Income Tax Disclosures,” which requires disaggregated information about the Company’s
effective tax rate reconciliation and income taxes paid. This ASU is effective for annual periods beginning after December 15, 2024 on
a prospective basis and early adoption is permitted. The Company is currently evaluating the impact of this standard on its tax disclosures.
 


ITEM
  7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 
The
primary source of market risk for us includes fluctuations in commodity prices and interest rates. All of our financial instruments are
for purposes other than trading.
 
Credit
Risk. Credit risk is the risk of loss as a result of nonperformance by other parties of their contractual obligations. Our primary
credit risk is related to oil and gas production sold to various purchasers and the receivables are generally not collateralized. At
March 31, 2024, our largest credit risk associated with any single purchaser was $480,836 or 48% of our total oil and gas receivables.
We have not experienced any significant credit losses.
 
Energy
Price Risk. Our most significant market risk is the pricing applicable to our crude oil and natural gas production. Our financial
condition, results of operations, and capital resources are highly dependent upon the prevailing market prices of, and demand for, oil
and natural gas. Prices for oil and natural gas production has been volatile and unpredictable for several years, and we expect this
volatility to continue in the future.
 
Factors
that can cause price fluctuations include the level of global demand for petroleum products, foreign and domestic supply of oil and gas,
the establishment of and compliance with production quotas by oil-exporting countries, weather conditions, the price and availability
of alternative fuels and overall political and economic conditions in oil producing and consuming countries.
 
For
example, in the last twelve months, the NYMEX West Texas Intermediate (“WTI”) posted price for crude oil has ranged from
a low of $63.10 per bbl in June 2023 to a high of $89.66 per bbl in September 2023. The Henry Hub Spot Market Price (“Henry Hub”)
for natural gas has ranged from a low of $1.25 per MMBtu in March 2024 to a high of $3.34 per MMBtu in October 2023. On March 31, 2024
the WTI posted price for crude oil was $79.15 per bbl and the Henry Hub spot price for natural gas was $1.54 per MMBtu. See Results of
Operations above for the Company’s realized prices during the fiscal year. Subsequently, on June 18, 2024, the WTI posted price
for crude oil was $77.55 and the Henry Hub posted price for natural gas was $2.43.
 

30
 

 
Declines
in oil and natural gas prices will materially adversely affect our financial condition, liquidity, ability to obtain financing and operating
results. Changes in oil and gas prices impact both estimated future net revenue and the estimated quantity of proved reserves. Any reduction
in reserves, including reductions due to price fluctuations, can reduce the borrowing base under our credit facility and adversely affect
the amount of cash flow available for capital expenditures and our ability to obtain additional capital for our acquisition, exploration
and development activities. In addition, a noncash write-down of our oil and gas properties could be required under full cost accounting
rules if prices declined significantly, even if it is only for a short period of time. See Critical Accounting Policies and Estimates
— Ceiling Test under Item 7 of this report on Form 10-K. Lower prices may also reduce the amount of crude oil and natural gas that
can be produced economically. Thus, we may experience material increases or decreases in reserve quantities solely as a result of price
changes and not as a result of drilling or well performance.
 
Similarly,
any improvements in oil and gas prices can have a favorable impact on our financial condition, results of operations and capital resources.
Oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. If the average oil price had increased
or decreased by ten dollars per barrel for fiscal 2024, our pretax income would have changed by $699,990. If the average gas price had
increased or decreased by one dollar per mcf for fiscal 2024, pretax income would have changed by $502,879.
 



ITEM
  8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

 
The
information required by this item appears on pages F2 through F21 hereof and are incorporated herein by reference.
 
 


ITEM
  9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING
AND FINANCIAL DISCLOSURES

 
None.
 



ITEM
  9A.
CONTROLS AND PROCEDURES

 
Management’s
Annual Report on Internal Control over Financial Reporting. The management of the Company is responsible for establishing and maintaining
adequate internal control over financial reporting as such term is defined in Exchange Act Rule 13a-15(f) and 15d-15(f). The Company’s
internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting
and the preparation of the consolidated financial statements. Because of its inherent limitations, internal control over financial reporting
may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk
that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures
may deteriorate.
 
Our
internal control over financial reporting is supported by appropriate reviews by management, written policies and guidelines, careful
selection and training of qualified personnel, and a written Code of Conduct adopted by our Board of Directors, applicable to all directors,
officers and employees of Mexco.
 
Our
chief executive officer and chief financial officer assessed the effectiveness our internal control over financial reporting using the
criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission in the 2013 “Internal Control - Integrated
Framework”. Based upon that evaluation, our chief executive officer and chief financial officer concluded that our internal control
over financial reporting was effective as of March 31, 2024.
 
Evaluation
of Disclosure Controls and Procedures. We maintain disclosure controls and procedures to ensure that the information we must disclose
in our filings with the SEC is recorded, processed, summarized and reported on a timely basis. At the end of the period covered by this
report, our principal executive officer and principal financial officer reviewed and evaluated the effectiveness of our disclosure controls
and procedures, as defined in Exchange Act Rule 13a-15(e). Based on such evaluation, such officers concluded that, as of March 31, 2024,
our disclosure controls and procedures were effective.
 

31
 

 
Changes
in Internal Control over Financial Reporting. No changes in the Company’s internal control over financial reporting occurred
during the year ended March 31, 2024 that have materially affected, or are reasonably likely to materially affect, our internal control
over financial reporting.
 


ITEM
  9B.
OTHER INFORMATION

 
None
 



ITEM
  9C.
DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT
INSPECTION

 
Not
applicable
 

PART
III
 


ITEM
  10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

 
See
“Mexco Energy Corporation Board of Directors”, “Named Executive Officers Who Are Not Directors”, “Section
16(a) Beneficial Ownership Reporting Compliance”, “Corporate Governance and Code of Business Conduct” and “Meetings
and Committees of the Board of Directors” in the Proxy Statement of Mexco Energy Corporation for our Annual Meeting of Stockholders
to be held September 10, 2024 (“Proxy Statement”) to be filed with the SEC within 120 days after the end of our fiscal year
ended March 31, 2024, which is incorporated herein by reference.
 
The
information required by this item with respect to executive officers of the Company is also set forth in Part I of this report.
 



ITEM
  11.
EXECUTIVE COMPENSATION

 
The
information required by this item will be contained in the Proxy Statement under the caption “Executive Compensation”, and
is hereby incorporated herein by reference.
 



ITEM
  12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
AND RELATED STOCKHOLDER MATTERS

 
The
information required by this item will be contained in the Proxy Statement under the captions “Security Ownership of Certain Beneficial
Owners and Management” and “Employee Incentive Stock Option Plans”, and is hereby incorporated herein by reference.
 



ITEM
  13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR
INDEPENDENCE

 
The
information required by this item will be contained in the Proxy Statement under the captions “Certain Relationships and Related
Transactions” and “Meetings and Committees of the Board of Directors”, and is hereby incorporated by reference herein.
 



ITEM
  14.
PRINCIPAL ACCOUNTING FEES AND SERVICES

 
The
information required by this item will be contained in the Proxy Statement under the caption “Audit Fees and Services”, and
is hereby incorporated by reference herein.

 

32
 

 
PART
IV
 


ITEM
  15.
EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

 
Consolidated
Financial Statements. For a list of the consolidated financial statements filed as part of this Form 10-K, see the “Index to
Consolidated Financial Statements” set forth on F-1 of this report.
 
Financial
Statement Schedules. All schedules have been omitted because they are not applicable, not required under the instructions or the
information requested is set forth in the consolidated financial statements or related notes thereto.
 
Exhibits.
For a list of the exhibits required by this Item and accompanying this Form 10-K see the “Index to Exhibits” set forth
on page F22 of this report.
 


ITEM
  16.
FORM 10-K SUMMARY

 
None
 


33
 

 
SIGNATURES
 
Pursuant
to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed
on its behalf by the undersigned, thereunto duly authorized.
 


MEXCO
    ENERGY CORPORATION
 
 
 

 
 
 
 
 

By:
/s/
    Nicholas C. Taylor
 
By:
/s/
    Tamala L. McComic 

 
Chairman
    of the Board and Chief Executive Officer 
 
 
President
    and Chief Financial Officer

 
 
 
 
 

Dated:
    June 27, 2024
 
 
 

 

Pursuant
to the requirements of the Securities Exchange Act of 1934, this report has been signed below as of June 27, 2024, by the following persons
on behalf of the Registrant and in the capacity indicated.
 



/s/
    Nicholas C. Taylor
 

Nicholas
    C. Taylor
 

Chief
    Executive Officer, Chairman of the Board of Directors
 

 
 

/s/
    Tamala L. McComic
 

Tamala
    L. McComic
 

Chief
    Financial Officer, President, Treasurer and Assistant Secretary
 

 
 

/s/
    Michael J. Banschbach
 

Michael
    J. Banschbach
 

Director
 

 
 

/s/
    Kenneth L. Clayton
 

Kenneth
    L. Clayton
 

Director
 

 
 

/s/
    Thomas R. Craddick
 

Thomas
    R. Craddick
 

Director
 

 
 

/s/
    Thomas H. Decker
 

Thomas
    H. Decker
 

Director
 

 
 

/s/
    Christopher M. Schroeder
 

Christopher
    M. Schroeder
 

Director
 

 

34
 

 
Glossary
of Abbreviations and Terms
 
The
following are abbreviations and definitions of terms commonly used in the oil and gas industry and this report.
 
Basin.
A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
 
Bbl.
One stock tank barrel, or 42 U.S. gallons of liquid volume, used herein in reference to crude oil, condensate or natural gas liquids
hydrocarbons.
 
BOE.
Barrels of oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of oil.
 
BTU.
British thermal unit.
 
Completion.
The installation of permanent equipment for the production of oil or natural gas.
 
Condensate.
Liquid hydrocarbons associated with the production of a primarily natural gas reserve.
 
Credit
Facility. A line of credit provided by a bank or group of banks, secured by oil and gas properties.
 
DD&A.
Refers to depreciation, depletion and amortization of the Company’s property and equipment.
 
Developed
acreage. The number of acres which are allocated or assignable to producing wells or wells capable of production.
 
Development
costs. Capital costs incurred in the acquisition, exploitation and exploration of proved oil and natural gas reserves divided by
proved reserve additions and revisions to proved reserves.
 
Development
well. A well drilled into a proved oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
 
Dry
hole. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production
exceed production expenses and taxes.
 
Exploration.
The search for natural accumulations of oil and natural gas by any geological, geophysical or other suitable means.
 
Exploratory
well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field
previously found to be productive of oil or natural gas in another reservoir or to extend a known reservoir.
 
Extensions
and discoveries. As to any period, the increases to proved reserves from all sources other than the acquisition of proved properties
or revisions of previous estimates.
 
Field.
An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological
structural feature and/or stratigraphic condition.
 
Formation.
A layer of rock which has distinct characteristics that differs from nearby rock.
 
Gross
acres or wells. Refers to the total acres or wells, as the case may be, in which an interest is owned any amount of working interest.
 
Lease.
An instrument which grants to another (the lessee) the exclusive right to enter and explore for, drill for, produce, store and remove
oil and natural gas from the mineral interest, in consideration for which the lessor is entitled to certain rents and royalties payable
under the terms of the lease. Typically, the duration of the lessee’s authorization is for a stated term of years and “for
so long thereafter” as minerals are producing.
 
Mcf.
One thousand cubic feet of natural gas.
 

35
 

 
MBOE.
One thousand barrels of oil equivalent.
 
MMBOE.
One million barrels of oil equivalent.
 
MMBtu.
One million British thermal units of energy commonly used to measure heat value or energy content of natural gas.
 
Natural
gas liquids (“NGLs”). Liquid hydrocarbons that have been extracted from natural gas, such as ethane, propane, butane
and natural gasoline.
 
Net
acres or wells. Refers to gross acres or wells multiplied, in each case, by the percentage interest owned by the Company.
 
Net
production. Oil and gas production that is owned by the Company, less royalties and production due others.
 
Net
revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding
interests.
 
Oil.
Crude oil or condensate.
 
Operator.
The individual or company responsible for the exploration, development and production of an oil or natural gas well or lease.
 
Overriding
royalty interest (“ORRI”). A royalty interest that is created out of the operating or working interest. Its term is coextensive
with that of the operating interest from which it was created.
 
Plugging
and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will
not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.
 
Productive
well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the
production exceed operating and production expenses and taxes.
 
Prospect.
A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis
using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.
 
Proved
developed nonproducing reserves (“PDNP”). Reserves that consist of (i) proved reserves from wells which have been completed
and tested but are not producing due to lack of market or minor completion problems which are expected to be corrected and (ii) proved
reserves currently behind the pipe in existing wells and which are expected to be productive due to both the well log characteristics
and analogous production in the immediate vicinity of the wells.
 
Proved
developed producing reserves (“PDP”). Proved reserves that can be expected to be recovered from currently producing zones
under the continuation of present operating methods.
 
Proved
developed reserves. The combination of proved developed producing and proved developed nonproducing reserves.
 
Proved
reserves. The estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating
conditions.
 
Proved
undeveloped reserves (“PUD”). Proved reserves that are expected to be recovered from new wells on undrilled acreage or
from existing wells where a relatively major expenditure is required for recompletion.
 

36
 

 
PV-10.
When used with respect to oil and natural gas reserves, PV-10 means the estimated future gross revenue to be generated from the production
of proved reserves, net of estimated production and future development and abandonment costs, using prices and costs in effect at the
determination date, before income taxes, and without giving effect to non-property-related expenses except for specific general and administrative
expenses incurred to operate the properties, discounted to a present value using an annual discount rate of 10%.
 
Recompletion.
A process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt
to establish or increase existing production.
 
Reservoir.
A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined
by impermeable rock or water barriers and is separate from other reservoirs.
 
Royalty.
An interest in an oil and natural gas lease that gives the owner of the interest the right to receive a portion of the production from
the leased acreage, or of the proceeds of the sale thereof, but generally does not require the owner to pay any portion of the costs
of drilling or operating the wells on the leased acreage. Royalties may be either landowner’s royalties, which are reserved by
the owner of the leased acreage at the time the lease is granted, or overriding royalties, which are usually reserved by an owner of
the leasehold in connection with a transfer to a subsequent owner.
 
Shut
in. A well suspended from production or injection but not abandoned.
 
Spacing.
The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing)
and is often established by regulatory agencies.
 
Standardized
measure of discounted future net cash flows. The discounted future net cash flows relating to proved reserves based on prices used
in estimating the reserves, year-end costs, and statutory tax rates, and a 10% annual discount rate. The information for this calculation
is included in the note regarding disclosures about oil and gas reserve data contained in the Notes to Consolidated Financial Statements
included in this Form 10-K.
 
Undeveloped
acreage. Leased acreage on which wells have not been drilled or completed to a point that would permit the production of commercial
quantities of oil and natural gas regardless of whether such acreage contains proved reserves.
 
Unit.
The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development
and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
 
Wellbore.
The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called well or borehole.
 
Working
interest. An interest in an oil and gas lease that gives the owner of the interest the right to drill for and produce oil and natural
gas on the leased acreage and requires the owner to pay a share of the costs of drilling and production operations. The share of production
to which a working interest is entitled will be smaller than the share of costs that the working interest owner is required to bear to
the extent of any royalty burden.
 

37
 

 
INDEX
TO CONSOLIDATED FINANCIAL STATEMENTS
 


Report of Independent Registered Public Accounting Firm
F-2

Consolidated Balance Sheets
F-4

Consolidated Statements of Operations
F-5

Consolidated Statements of Changes in Stockholders’ Equity
F-6

Consolidated Statements of Cash Flows
F-7

Notes to Consolidated Financial Statements
F-8

 

F-1
 

 
Report
of Independent Registered Public Accounting Firm
 
Board
of Directors and Shareholders
Mexco
Energy Corporation
 
Opinion
on the Financial Statements
 
We
have audited the accompanying consolidated balance sheets of Mexco Energy Corporation (a Colorado corporation) and Subsidiaries (the
Company) as of March 31, 2024 and 2023, and the related consolidated statements of operations, changes in stockholders’ equity,
and cash flows for each of the two years in the period ended March 31, 2024, and the related notes (collectively referred to as the “financial
statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the
Company as of March 31, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended
March 31, 2024, in conformity with accounting principles generally accepted in the United States of America.
 
Basis
for Opinion
 
These
financial statements are the responsibility of the entity’s management. Our responsibility is to express an opinion on these financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United
States) (“PCAOB”) and are required to be independent with respect to Mexco
Energy Corporation in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
 
We
conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company
is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits
we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion
on the effectiveness of the entity’s internal control over financial reporting. Accordingly, we express no such opinion.
 
Our
audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error
or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding
the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits
provide a reasonable basis for our opinion.
 
Critical
Audit Matters
 
The
critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated
or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial
statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters
does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit
matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
 
Estimation
of proved reserves impacting the recognition and valuation of depletion expense and impairment of oil and gas properties. 
 
Critical
Accounting Matter Description 
 
As
described in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting
which requires management to make estimates of proved reserve volumes and future revenues and expenses to calculate depletion expense. To estimate the volume of proved reserves and future revenues, management
makes significant estimates and assumptions, including forecasting the production decline rate of producing properties and forecasting
the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition,
the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance
of wells associated with proved reserves to determine if wells are expected, with reasonable certainty, to be economical under the appropriate
pricing assumptions required in the estimation of depletion expense. We identified the estimation
of proved reserves of oil and gas properties, due to its impact on depletion expense and impairment evaluation, as a critical audit matter.
 

F-2
 

 
The
principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain
inputs and assumptions, which require a high degree of subjectivity necessary to estimate the volume and future revenues of the Company’s
proved reserves could have a significant impact on the measurement of depletion expense or the impairment assessment. In turn, auditing
those inputs and assumptions required subjective and complex auditor judgment.
 
How
the Critical Audit Matter Was Addressed in the Audit 
 
We
obtained an understanding of the design and implementation of management’s controls and our audit procedures related to the estimation
of proved reserves included the following, among others.
 
●
We evaluated the level of knowledge, skill, and ability of the Company’s reservoir engineering specialists and their relationship
to the Company, made inquiries of those reservoir engineers regarding the process followed and judgments made to estimate the Company’s
proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
 
●
To the extent key, sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions
are derived from the Company’s accounting records, such as commodity pricing, historical pricing differentials, operating costs,
estimated capital costs and working and net revenue interests, we tested management’s process for determining the assumptions,
including examining the underlying support, on a sample basis. Specifically, our audit procedures involved testing management’s
assumptions as follows:
 

-Compared
                                            the estimated pricing differentials used in the reserve report to realized prices related
                                            to revenue transactions recorded in the current year;

   

-Evaluated
                                            the models used to estimate the operating costs at year-end compared to historical operating
                                            costs;

   

-Compared
                                            the models used to determine the future capital expenditures and compared estimated future
                                            capital expenditures used in the reserve report to amounts expended for recently drilled
                                            and completed wells with similar locations;

   

-Evaluated
                                            the working and net revenue interests used in the reserve report by inspecting a sample of
                                            ownership interests, historical pricing differentials, and operating costs to underlying
                                            support from the Company’s accounting records.

   

-Evaluated
                                            the Company’s evidence supporting the amount of proved undeveloped properties reflected
                                            in the reserve report by examining historical conversion rates and support for the Company’s
                                            or the operator’s intent to develop the proved undeveloped properties;

   

-Applied
                                            analytical procedures to the reserve report by comparing to historical actual results and
                                            to the prior year reserve report.
 
/s/
WEAVER AND TIDWELL, L.L.P.
 
We
have served as the Company’s auditor since 2017.
 
PCAOB
ID #410
Midland,
Texas
June
27, 2024
 

F-3
 

 
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED
BALANCE SHEETS
 


  
March 31,  
March 31, 

  
2024  
2023 

ASSETS 
    
   

Current assets 
    
   

Cash and cash equivalents 
$2,473,484  
$2,235,771 

Accounts receivable: 
    
   

Oil and natural gas sales 
 1,001,709  
 1,366,784 

Trade 
 9,186  
 7,031 

Prepaid drilling 
 148,748  
 67,951 

Prepaid costs and expenses 
 56,193  
 56,502 

Total current assets 
 3,689,320  
 3,734,039 

Property and equipment, at cost 
    
   

Oil and gas properties, using the full cost method 
 48,304,585  
 45,391,634 

Other 
 121,926  
 121,926 

Accumulated depreciation, depletion and amortization 
 (34,184,837) 
 (32,215,095)

Property and equipment, net 
 14,241,674  
 13,298,465 

Investment – cost basis 
 1,100,000  
 700,000 

Operating lease, right-of-use asset 
 19,263  
 75,629 

Other noncurrent assets 
 8,597  
 12,156 

Total assets 
$19,058,854  
$17,820,289 

  
    
   

LIABILITIES AND STOCKHOLDERS’ EQUITY 
    
   

Current liabilities 
    
   

Accounts payable and accrued expenses 
$221,603  
$201,897 

Income tax payable 
 189,254  
 - 

Operating lease liability, current 
 19,263  
 56,366 

Total current liabilities 
 430,120  
 258,263 

Long-term liabilities 
    
   

Operating lease liability, long-term 
 -  
 19,263 

Deferred income tax liability 
 311,661  
 - 

Asset retirement obligations 
 688,808  
 710,276 

Total long-term liabilities 
 1,000,469  
 729,539 

Total liabilities 
 1,430,589  
 987,802 

  
    
   

Commitments and contingencies 
 -  
 - 

  
    
   

Stockholders’ equity 
    
   

  
    
   

Preferred stock - $1.00 par value; 10,000,000 shares authorized; none outstanding 
 -  
 - 

Common stock - $0.50 par value; 40,000,000 shares authorized; 2,226,916 and 2,221,416 shares issued;
    and, 2,091,399 and 2,136,000 shares outstanding as of March 31, 2024 and 2023 
 1,113,458  
 1,110,708 

Additional paid-in capital 
 8,567,856  
 8,321,145 

Retained earnings 
 9,122,481  
 7,991,129 

Treasury stock, at cost (135,517 and 85,416 shares, respectively) 
 (1,175,530) 
 (590,495)

Total stockholders’ equity 
 17,628,265  
 16,832,487 

Total liabilities and stockholders’ equity 
$19,058,854  
$17,820,289 

 
The
accompanying notes to the consolidated financial statements are an integral part of these statements.
 

F-4
 

 
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED
STATEMENTS OF OPERATIONS
Years
ended March 31,
 


  
2024  
2023 

Operating revenues: 
    
   

Oil sales 
$5,348,257  
$6,522,163 

Natural gas sales 
 1,114,390  
 2,858,460 

Other 
 142,237  
 176,666 

Total operating revenues 
 6,604,884  
 9,557,289 

  
    
   

Operating expenses: 
    
   

Production 
 1,526,472  
 1,719,719 

Accretion of asset retirement obligation 
 29,869  
 30,532 

Depreciation, depletion and amortization 
 1,969,742  
 1,854,047 

General and administrative 
 1,243,547  
 1,120,691 

Total operating expenses 
 4,769,630  
 4,724,989 

  
    
   

Operating income 
 1,835,254  
 4,832,300 

  
    
   

Other income (expenses): 
    
   

Interest income 
 135,476  
 8,009 

Interest expense 
 (5,234) 
 (13,097)

Net other expense 
 130,242  
 (5,088)

  
    
   

Income before provision for income taxes 
 1,965,496  
 4,827,212 

  
    
   

Income tax expense: 
    
   

Current 
 308,883  
 164,510 

Deferred 
 311,661  
 - 

Total income tax expense 
 620,544  
 164,510 

  
    
   

Net income 
$1,344,952  
$4,662,702 

  
    
   

  
    
   

Income per common share: 
    
   

Basic: 
$0.64  
$2.17 

Diluted: 
$0.62  
$2.11 

  
    
   

Weighted average common shares outstanding: 
    
   

Basic: 
 2,114,360  
 2,146,491 

Diluted: 
 2,161,010  
 2,208,663 

 
The
accompanying notes to the consolidated financial statements are an integral part of these statements.
 

F-5
 

 
Mexco
Energy Corporation and Subsidiaries
CONSOLIDATED
STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
Years
ended March 31, 2024 and 2023
 


  
Common Stock Par Value  
Additional Paid-In Capital  
Retained Earnings  
Treasury Stock  
Total Stockholders’ Equity 

Balance at April 1, 2022 
$1,108,208  
$8,133,982  
$3,328,427  
$(346,001) 
$12,224,616 

Net income 
 -  
 -  
 4,662,702  
 -  
 4,662,702 

Issuance of stock through options exercised 
 2,500  
 14,200  
 -  
 -  
 16,700 

Profit from purchase of stock by insider 
    
 30,179  
    
    
 30,179 

Purchase of stock 
    
    
    
 (244,494) 
 (244,494)

Stock based compensation 
 -  
 142,783  
 -  
 -  
 142,783 

Balance at March 31, 2023 
$1,110,708  
$8,321,145  
$7,991,129  
$(590,495) 
$16,832,487 

Balance 
$1,110,708  
$8,321,145  
$7,991,129  
$(590,495) 
$16,832,487 

Net income 
 -  
 -  
 1,344,952  
 -  
 1,344,952 

Issuance of stock through options exercised 
 2,750  
 16,912  
 -  
 -  
 19,662 

Dividends paid 
    
    
 (213,600) 
    
 (213,600)

Purchase of stock 
 -  
 -  
 -  
 (585,035) 
 (585,035)

Stock based compensation 
 -  
 229,799  
 -  
 -  
 229,799 

Balance at March 31, 2024 
$1,113,458  
$8,567,856  
$9,122,481  
$(1,175,530) 
$17,628,265 

Balance 
$1,113,458  
$8,567,856  
$9,122,481  
$(1,175,530) 
$17,628,265 

 


SHARE ACTIVITY 
   
  

  
2024  
2023 

Common stock shares, issued: 
    
   

At beginning of year 
 2,221,416  
 2,216,416 

Issued 
 5,500  
 5,000 

At end of year 
 2,226,916  
 2,221,416 

  
    
   

Common stock shares, held in treasury: 
    
   

At beginning of year 
 (85,416) 
 (67,000)

Acquisitions 
 (50,101) 
 (18,416)

At end of year 
 (135,517) 
 (85,416)

  
    
   

Common stock shares, outstanding 
    
   

At end of year 
 2,091,399  
 2,136,000 

 
The
accompanying notes to the consolidated financial statements are an integral part of these statements.
 

F-6
 

 
Mexco Energy Corporation and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
Years ended March 31,
 


  
2024  
2023 

Cash flows from operating activities: 
    
   

Net income 
$1,344,952  
$4,662,702 

Adjustments to reconcile net income to net cash provided by operating activities: 
    
   

Deferred income tax expense 
 311,661  
 - 

Stock-based compensation 
 229,799  
 142,783 

Depreciation, depletion and amortization 
 1,969,742  
 1,854,047 

Accretion of asset retirement obligations 
 29,869  
 30,532 

Amortization of debt issuance costs 
 4,309  
 12,570 

Changes in operating assets and liabilities: 
    
   

Decrease (increase) in accounts receivable 
 362,920  
 (63,678)

Decrease in right-of-use asset 
 56,366  
 54,294 

Decrease (increase) in prepaid expenses 
 309  
 (8,866)

Increase (decrease) in accounts payable and accrued expenses 
 16,198  
 (33,475)

Decrease in operating lease liability 
 (56,366) 
 (54,294)

Increase in income tax payable 
 189,254  
 - 

Settlement of asset retirement obligations 
 (25,078) 
 (80,720)

Net cash provided by operating activities 
 4,433,935  
 6,515,895 

  
    
   

Cash flows from investing activities: 
    
   

Additions to oil and gas properties 
 (3,349,326) 
 (5,310,036)

Additions to other property and equipment 
 -  
 (1,718)

Drilling refund 
 26,194  
 295,679 

Investment in limited liability companies at cost 
 (400,000) 
 (425,000)

Proceeds from sale of oil and gas properties and equipment 
 306,633  
 - 

Net cash used in investing activities 
 (3,416,499) 
 (5,441,075)

  
    
   

Cash flows from financing activities: 
    
   

Proceeds from exercise of stock options 
 19,662  
 16,700 

Profits from purchase of stock by insider 
 -  
 30,179 

Proceeds from long-term debt 
 275,000  
 675,000 

Debt issuance costs 
 (750) 
 (12,200)

Dividends paid 
 (213,600) 
 - 

Acquisition of treasury stock 
 (585,035) 
 (244,494)

Reduction of long-term debt 
 (275,000) 
 (675,000)

Net cash used in financing activities 
 (779,723) 
 (209,815)

  
    
   

Net increase in cash and cash equivalents 
 237,713  
 865,005 

  
    
   

Cash and cash equivalents at beginning of year 
 2,235,771  
 1,370,766 

  
    
   

Cash and cash equivalents at end of year 
$2,473,484  
$2,235,771 

  
    
   

Supplemental disclosure of cash flow information: 
    
   

Cash paid for interest 
$925  
$528 

Accrued capital expenditures included in accounts payable 
$21,693  
$28,186 

  
    
   

Non-cash investing and financing activities: 
    
   

Asset retirement obligations 
$7,617  
$23,492 

 
The
accompanying notes to the consolidated financial statements are an integral part of these statements.
 

F-7
 

 
MEXCO
ENERGY CORPORATION AND SUBSIDIARIES
NOTES
TO CONSOLIDATED FINANCIAL STATEMENTS
Years
Ended March 31, 2024 and 2023
 
1.
Nature of Operations
 
Mexco
Energy Corporation (a Colorado corporation) and its wholly owned subsidiaries, Forman Energy Corporation (a New York corporation), Southwest
Texas Disposal Corporation (a Texas corporation) and TBO Oil & Gas, LLC (a Texas limited liability company) (collectively, the “Company”)
are engaged in the acquisition, exploration, development and production of crude oil, natural gas, condensate and natural gas liquids
(“NGLs”). Most of the Company’s oil and gas interests are centered in West Texas and Southeastern New Mexico; however,
the Company owns producing properties and undeveloped acreage in fourteen states. All of the Company’s oil and gas interests are
operated by others.
 
2.
Summary of Significant Accounting Policies
 
Principles
of Consolidation. The consolidated financial statements include the accounts of Mexco Energy Corporation and its wholly owned subsidiaries.
All significant intercompany balances and transactions associated with the consolidated operations have been eliminated.
 
Estimates
and Assumptions. In preparing financial statements in conformity with accounting principles generally accepted in the United States
of America (“GAAP”), management is required to make informed judgments, estimates and assumptions that affect the reported
amounts of assets and liabilities as of the date of the consolidated financial statements and affect the reported amounts of revenues
and expenses during the reporting period. In addition, significant estimates are used in determining proved oil and gas reserves. Although
management believes its estimates and assumptions are reasonable, actual results may differ materially from those estimates. The estimate
of the Company’s oil and natural gas reserves, which is used to compute depreciation, depletion, amortization and impairment of
oil and gas properties, is the most significant of the estimates and assumptions that affect these reported results.
 
Cash
and Cash Equivalents. The Company considers all highly liquid debt instruments purchased with maturities of three months or less
and money market funds to be cash equivalents. The Company maintains cash in bank deposit accounts that may, at times, exceed federally
insured limits. At March 31, 2024, the Company had on deposit all of its cash and cash equivalents with three financial institutions.
The Company has not experienced any losses in such accounts and believes it is not exposed to any significant credit risk.
 
Accounts
Receivable. Accounts receivable includes trade receivables from joint interest owners and oil and gas purchasers. Credit
is extended based on an evaluation of a customer’s financial condition and, generally, is uncollateralized. Accounts
receivable under joint operating agreements have a right of offset against future oil and gas revenues if a producing well is
completed. The collectibility of receivables is assessed and an allowance is made for any credit losses. The allowance for credit
losses is determined based on a number of factors, including the length of time accounts receivable are past due, the
Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and
the industry as a whole. The Company has not experienced any significant credit losses. For the years ended March 31,
2024 and 2023, no
allowance has been made for any credit losses.
 
Oil
and Gas Properties. Oil and gas properties are accounted for using the full cost method of accounting. Under this method of accounting,
the costs of unsuccessful, as well as successful, acquisition, exploration and development activities are capitalized as property and
equipment. This includes any internal costs that are directly related to exploration and development activities but does not include
any costs related to production, general corporate overhead or similar activities. The carrying amount of oil and gas properties also
includes estimated asset retirement costs recorded based on the fair value of the asset retirement obligation (“ARO”) when
incurred. Generally, no gains or losses are recognized on the sale or disposition of oil and gas properties.
 
Excluded
Costs. Oil and gas properties include costs that are excluded from capitalized costs being amortized. These amounts represent investments
in unproved properties and major development projects. These costs are excluded until proved reserves are found or until it is determined
that the costs are impaired. All costs excluded are reviewed at least quarterly to determine if impairment has occurred. The amount of
any impairment is transferred to the capitalized costs being amortized (the depreciation, depletion and amortization (“DD&A”)
pool). Impairments transferred to the DD&A pool increase the DD&A rate. No costs were excluded for the years ended March 31,
2024 and 2023.
 

F-8
 

 
Ceiling
Test. Under the full cost method of accounting, a ceiling test is performed each quarter. The full cost ceiling test is an impairment
test to determine a limit, or ceiling, on the book value of oil and gas properties. That limit is the after-tax present value of the
future net cash flows from proved crude oil and natural gas reserves and using an average price over the prior first day of the month
12-month period held flat for the life of production plus the lower of cost or fair market value of unproved properties. If net capitalized
costs of crude oil and natural gas properties exceed the ceiling limit, the Company must charge the amount of the excess to earnings
as an expense reflected in additional accumulated DD&A. This is called a “ceiling limitation write-down.” This impairment
to our oil and gas properties does not impact cash flow from operating activities, but does reduce stockholders’ equity and reported
earnings.
 
Depreciation,
Depletion and Amortization. The depreciable base for oil and gas properties includes the sum of capitalized costs, net of accumulated
DD&A, estimated future development costs and asset retirement costs not accrued in oil and gas properties, less costs excluded from
amortization and salvage. The depreciable base of oil and gas properties is amortized using the unit-of-production method.
 
Asset
Retirement Obligations. The Company has significant obligations to plug and abandon natural gas and crude oil wells and related equipment
at the end of oil and gas production operations. The Company records the fair value of a liability for an ARO in the period in which
it is incurred and a corresponding increase in the carrying amount of the related asset. Subsequently, the asset retirement costs included
in the carrying amount of the related asset are allocated to expense using the units of production method. In addition, increases in
the discounted ARO liability resulting from the passage of time are reflected as accretion expense in the Consolidated Statements of
Operations.
 
Estimating
the future ARO requires management to make estimates and judgments regarding timing and existence of a liability, as well as what constitutes
adequate restoration. The Company uses the present value of estimated cash flows related to the ARO to determine the fair value. Inherent
in the present value calculation are numerous assumptions and judgments including the ultimate costs, inflation factors, credit adjusted
discount rates, timing of settlement, and changes in the legal, regulatory, environmental and political environments. To the extent future
revisions to these assumptions impact the present value of the existing ARO liability, a corresponding adjustment is made to the related
asset.
 
Income
Taxes. The Company recognizes deferred tax assets and liabilities for future tax consequences of temporary differences between the
carrying amounts of assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted
tax rates applicable to the years in which those differences are expected to be settled. The effect on deferred tax assets and liabilities
of a change in tax rates is recognized in net income in the period that includes the enactment date. Any interest and penalties are recorded
as interest expense and general and administrative expense, respectively.
 
Other
Property and Equipment. Provisions for depreciation of office furniture and equipment are computed on the straight-line method based
on estimated useful lives of three to ten years.
 
Income
Per Common Share. Basic net income per share is computed by dividing net income by the weighted average number of common shares outstanding
during the period. Diluted net income per share assumes the exercise of all stock options having exercise prices less than the average
market price of the common stock during the period using the treasury stock method and is computed by dividing net income by the weighted
average number of common shares and dilutive potential common shares (stock options) outstanding during the period. In periods where
losses are reported, the weighted-average number of common shares outstanding excludes potential common shares, because their inclusion
would be anti-dilutive.
 
Revenue
Recognition - Revenue from Contracts with Customers. Revenues from our royalty and non-operated working interest properties are recorded
under the cash receipts approach as directly received from the remitters’ statement accompanying the revenue check. Since the revenue
checks are generally received two to three months after the production month, the Company accrues for revenue earned but not received
by estimating production volumes and product prices. Any identified differences between its revenue estimates and actual revenue received
historically have not been significant.
 


F-9
 

 
Gas
Balancing. Gas imbalances are accounted for under the sales method whereby revenues are recognized based on production sold. A liability
is recorded when excess takes of natural gas volumes exceed estimated remaining recoverable reserves (over produced). No receivables
are recorded for those wells where the Company has taken less than its ownership share of gas production (under produced). The Company
does not have any significant gas imbalances.
 
Stock-based
Compensation. The Company uses the Binomial option pricing model to estimate the fair value of stock-based compensation expenses
at grant date. This expense is recognized as compensation expense in its consolidated financial statements over the vesting period. The
Company recognizes the fair value of stock-based compensation awards as wages within general and administrative expense in the Consolidated
Statements of Operations based on a graded-vesting schedule over the vesting period.
 
Reclassifications.
Certain amounts in prior periods’ consolidated financial statements have been reclassified to conform with the current period’s
presentation. These reclassifications had no effect on previously reported results of operations, retained earnings or net cash flows.
 
Investments.
The Company accounts for investments of less than 3% in limited liability companies at cost. The Company has no control of the limited
liability companies. The cost of the investment is recorded as an asset on the consolidated balance sheets and when income from the investment
is received, it is immediately recognized on the consolidated statements of operations.
 
Liquidity
and Capital Resources. Historically, we have funded our operations, acquisitions, exploration and development expenditures from cash
generated by operating activities, bank borrowings, sales of non-core properties and issuance of common stock. Our long-term strategy
is on increasing profit margins while concentrating on obtaining reserves with low-cost operations by acquiring and developing oil and
gas properties with potential for long-lived production. We focus our efforts on the acquisition of royalties and working interest, non-operated
properties in areas with significant development potential.
 
Recent
Accounting Pronouncements. In December 2023, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards
Update (“ASU”) No. 2023-09, “Income Taxes (Topic 740): Improvements to Income Tax Disclosures,” which requires
disaggregated information about the Company’s effective tax rate reconciliation and income taxes paid. This ASU is effective for
annual periods beginning after December 15, 2024 on a prospective basis and early adoption is permitted. The Company is currently evaluating
the impact of this standard on its tax disclosures.
 
3.
Long-Term Debt
 
On
December 28, 2018, the Company entered into a loan agreement (the “Agreement”) with West Texas National Bank (“WTNB”),
which originally provided for a credit facility of $1,000,000 with a maturity date of December 28, 2021. The Agreement has no monthly
commitment reduction and a borrowing base to be evaluated annually.
 
On
February 28, 2020, the Agreement was amended to increase the credit facility to $2,500,000, extend the maturity date to March 28, 2023
and increase the borrowing base to $1,500,000. On March 28, 2023, the Agreement was amended to extend the maturity date to March 28,
2026.
 
Under
the Agreement, interest on the facility accrues at a rate equal to the prime rate as quoted in the Wall Street Journal plus one-half
of one percent (.5%) floating daily. Interest on the outstanding amount under the Agreement is payable monthly. In addition, the Company
will pay an unused commitment fee in an amount equal to one-half of one percent (.5%) times the daily average of the unadvanced amount
of the commitment. The unused commitment fee is payable quarterly in arrears on the last day of each calendar quarter. As of March 31,
2024, there was $1,500,000 available for borrowing by the Company on the facility.
 
No
principal payments are anticipated to be required through the maturity date of the credit facility, March 28, 2026. Upon closing the
second amendment to the Agreement, the Company paid a loan origination fee of $9,000 plus legal and recording expenses totaling $12,950,
which were also deferred over the life of the credit facility.
 

F-10
 

 
Amounts
borrowed under the Agreement are collateralized by the common stock of the Company’s wholly owned subsidiaries and substantially
all of the Company’s oil and gas properties.
 
The
Agreement contains customary covenants for credit facilities of this type including limitations on change in control, disposition of
assets, mergers and reorganizations. The Company is also obligated to meet certain financial covenants under the Agreement and requires
senior debt to earnings before interest, taxes, depreciation and amortization (“EBITDA”) ratios (Senior Debt/EBITDA) less
than or equal to 4.00 to 1.00 measured with respect to the four trailing quarters and minimum interest coverage ratios (EBITDA/Interest
Expense) of 2.00 to 1.00 for each quarter.
 
In
addition, the Agreement prohibits the Company from paying cash dividends on its common stock without prior written permission of
WTNB. The Company obtained written permission from WTNB prior to declaring the special dividend on April 10, 2023 and the regular
annual dividend on April 30, 2024 as discussed in Note 14. The Agreement does not permit the Company to enter into hedge agreements
covering crude oil and natural gas prices without prior WTNB approval.
 
There
was no balance outstanding on the credit facility as of March 31, 2024. The following table is a summary of activity on the WTNB credit
facility for the years ended March 31, 2024 and 2023:
Summary
of Line of Credit Activity


  
Principal 

Balance at April 1, 2022: 
$- 

Borrowings 
 675,000 

Repayments 
 (675,000)

Balance at March 31, 2023: 
$- 

Borrowings 
 275,000 

Repayments 
 (275,000)

Balance at March 31, 2024: 
$- 

 
 
4.
Asset Retirement Obligations
 
The
Company’s asset retirement obligations relate to the plugging of wells, the removal of facilities and equipment, and site restoration
on oil and gas properties. The fair value of a liability for an ARO is recorded in the period in which it is incurred, discounted to
its present value using the credit adjusted risk-free interest rate, and a corresponding amount capitalized by increasing the carrying
amount of the related long-lived asset. The liability is accreted each period until the liability is settled or the well is sold, at
which time the liability is removed. The related asset retirement cost is capitalized as part of the carrying amount of our oil and natural
gas properties. The ARO is included on the consolidated balance sheets with the current portion being included in the accounts payable
and accrued expenses.
 
The
following table provides a rollforward of the asset retirement obligations for fiscal years ended March 31:
Schedule of Rollforward of Asset Retirement Obligations


  
2024  
2023 

Carrying amount of asset retirement obligations, beginning of year 
$730,276  
$735,512 

Liabilities incurred 
 7,617  
 23,492 

Liabilities settled 
 (48,954) 
 (59,260)

Accretion expense 
 29,869  
 30,532 

Revisions 
 -  
 - 

Carrying amount of asset retirement obligations, end of year 
 718,808  
 730,276 

Less: Current portion 
 30,000  
 20,000 

Non-Current asset retirement obligation 
$688,808  
$710,276 

 

F-11
 

 
5.
Income Taxes
 
On
August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other
tax provisions, imposes a 15% corporate alternative minimum tax based on financial statement income, effective for tax years beginning
after December 31, 2022. The IRA 2022 also establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations,
effective for stock repurchases after December 31, 2022. The IRA 2022 did not impact the Company’s current year tax provision or
the Company’s consolidated financial statements.
 
The
Company files a consolidated federal income tax return and various state income tax returns. The amount of income taxes the Company records
requires the interpretation of complex rules and regulations of federal and state taxing jurisdictions. With few exceptions, the earliest
year open to examination by U.S. federal and state income tax jurisdictions is 2019.
 
The
income tax provision consists of the following for the years months ended March 31, 2024 and 2023:
 Schedule
of Income Tax Provision


  
2024  
2023 

  
Year Ended 

  
March 31 

  
2024  
2023 

Current income tax expense: 
    
   

Federal 
$189,254  
$- 

State 
 119,629  
 164,510 

Total current income tax expense 
$308,883  
$164,510 

Deferred income tax expense: 
    
   

Federal 
 311,661  
 - 

State 
 -  
 - 

Total deferred income tax expense 
$311,661  
$- 

Total income tax expense: 
$620,544  
$164,510 

 
Federal
income tax for the year ended March 31, 2024 was $500,915. There was no federal income tax expense for the year ended March 31, 2023
because the Company was in a net deferred tax asset position.
 
GAAP
requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences
are to be realized or settled. Significant components of net deferred tax assets (liabilities) at March 31 are as follows:
 Schedule of Components of Net Deferred Tax Assets (Liabilities)


  
2024  
2023 

Deferred tax assets: 
    
   

Percentage depletion carryforwards 
$1,281,990  
$1,375,131 

Deferred stock-based compensation 
 15,745  
 22,041 

Asset retirement obligation 
 150,950  
 153,358 

Net operating loss 
 151,193  
 665,386 

Other 
 35,345  
 11,642 

Total deferred tax assets 
$1,635,223  
$2,227,558 

Deferred tax liabilities: 
    
   

Excess financial accounting bases over tax bases of property and equipment 
 1,946,884  
 2,223,980 

Deferred tax liability, net 
$311,661  
$3,578 

Valuation allowance 
 -  
 (3,578)

Net deferred tax 
$311,661  
$- 

 
As
of March 31, 2024, the Company has a statutory depletion carryforward of approximately $5,400,000, which does not expire. At March 31,
2024, the Company had a net operating loss carryforward for regular income tax reporting purposes of approximately $720,000, which will
begin expiring in 2040. The Company’s ability to use some of its net operating loss carryforwards and certain other tax attributes
to reduce current and future U.S. federal taxable income is subject to limitations under the Internal Revenue Code.
 

F-12
 

 
A
valuation allowance for deferred tax assets, including net operating losses, is recognized when it is more likely than not that some
or all of the benefit from the deferred tax asset will not be realized. To assess that likelihood, we use estimates and judgment regarding
our future taxable income, and we consider the tax consequences in the jurisdiction where such taxable income is generated, to determine
whether a valuation allowance is required. Such evidence can include our current financial position, our results of operations, both
actual and forecasted, the reversal of deferred tax liabilities, and tax planning strategies as well as the current and forecasted business
economics of our industry.
 
A
reconciliation of the provision for income taxes to income taxes computed using the federal statutory rate for years ended March 31 follows:
 Schedule of Reconciliation of Provision for Income Taxes


  
2024  
2023 

Tax expense at federal statutory rate (1) 
$412,754  
$979,167 

Statutory depletion carryforward 
 152,054  
 (257,509)

Change in valuation allowance 
 (3,578) 
 (749,912)

U. S. tax reform, corporate rate reduction 
 -  
 - 

Permanent differences 
 46,819  
 28,196 

State income expense, net of federal benefit 
 94,507  
 164,510 

Other 
 (82,012) 
 58 

Total income tax 
$620,544  
$164,510 

Effective income tax rate 
 31.6% 
 3.4%

 

(1)The
                                            federal statutory rate was 21% for fiscal years ending March 31, 2024 and 2023.
 
For
the years ended March 31, 2024 and 2023, the Company did not have any uncertain tax positions.
 
While
the amount of unrecognized tax benefits may change in the next 12 months, the Company does not expect any change to have a significant
impact on its results of operations. The recognition of the total amount of the unrecognized tax benefits would have an impact on the
effective tax rate. If these unrecognized tax benefits are disallowed, the Company will be required to pay additional taxes.
 
6.
Major Customers
 
Currently,
the Company operates exclusively within the United States and its revenues and operating profit are derived from the oil and gas industry.
Oil and gas production is sold to various purchasers and the receivables are unsecured. Historically, the Company has not experienced
significant credit losses on its oil and gas accounts and management is of the opinion that significant credit risk does not exist. Management
is of the opinion that the loss of any one purchaser would not have an adverse effect on the Company’s ability to sell its oil
and gas production.
 
In
fiscal 2024, one purchaser accounted for 59% of the total operating revenues and 48% of the total oil and natural gas accounts receivable
and another purchaser accounted for 8% of the total operating revenues and 8% of the total oil and natural gas accounts receivable. In
fiscal 2023, one purchaser accounted for 53% of the total operating revenues and 46% of the total oil and natural gas accounts receivable
and another purchaser accounted for 8% of the total operating revenues and 21% of the total oil and natural gas accounts receivable.
 
7.
Oil and Natural Gas Costs
 
The
costs related to the Company’s oil and natural gas activities were incurred as follows for the years ended March 31:
 Schedule of Cost Related to Oil and Gas Activities


  
2024  
2023 

Property acquisition costs: 
    
   

Proved 
$1,826,266  
$1,053,442 

Unproved 
 -  
 - 

Exploration 
 153,039  
 - 

Development 
 1,363,529  
 4,282,499 

Capitalized asset retirement obligations 
 7,617  
 23,492 

Total costs incurred for oil and gas properties 
$3,350,451  
$5,359,433 

 

F-13
 

 
The
Company had the following aggregate capitalized costs relating to its oil and gas property activities at March 31:
 Schedule of Aggregate Capitalized Costs Relating Oil and Gas Property Activities


  
2024  
2023 

Proved oil and gas properties 
$48,304,585  
$45,391,634 

Unproved oil and gas properties: 
    
   

subject to amortization 
 -  
 - 

not subject to amortization 
 -  
 - 

Oil and gas properties, gross 
$48,304,585  
$45,391,634 

Less accumulated DD&A 
 34,066,282  
 32,099,439 

Total
    oil and gas properties 
$14,238,303  
$13,292,195 

 
DD&A
amounted to $12.81 and $14.56 per BOE of production for the years ended March 31, 2024 and 2023, respectively.
 
8.
Income Per Common Share
 
The
following is a reconciliation of the number of shares used in the calculation of basic income per share and diluted income per share
for the years ended March 31:
 
 Schedule of Reconciliation of Basic and Diluted Net Income (loss) Per Share


  
2024  
2023 

Net income 
$1,344,952  
$4,662,702 

  
    
   

Shares outstanding: 
    
   

Weighted avg. common shares outstanding – basic 
 2,114,360  
 2,146,491 

Effect of the assumed exercise of dilutive stock options 
 46,650  
 62,172 

Weighted avg. common shares outstanding – dilutive 
 2,161,010  
 2,208,663 

  
    
   

Income per common share: 
    
   

Basic 
$0.64  
$2.17 

Diluted 
$0.62  
$2.11 

 
For
the year ended March 31, 2024, 93,000 shares relating to stock options were excluded from the computation of diluted net income because
their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $13.12 at March 31, 2024.
For the year ended March 31, 2023, 31,000 shares relating to stock options were excluded from the computation of diluted net income because
their inclusion would be anti-dilutive. Anti-dilutive stock options have a weighted average exercise price of $18.05 at March 31, 2023.
 
9.
Stockholders’ Equity
 
In
March 2023, the Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock for
the treasury account. This program does not have an expiration date and may be modified, suspended or terminated at any time by the Board.
Under the repurchase program, share of common stock may be purchased from time to time through open market purchases or other transactions.
The amount and timing of repurchases will be subject to the availability of stock, prevailing market conditions, the trading price of
stock, our financial performance and other conditions. Repurchases may also be made form time-to-time in connection with the settlement
of our share-based compensation awards. Repurchases will be funded from cash flow.
 
On
August 16, 2022, President Biden signed into law the Inflation Reduction Act of 2022 (“IRA 2022”). The IRA 2022, among other
tax provisions, establishes a 1% excise tax on stock repurchases made by publicly traded U.S. corporations, effective for stock repurchases
in excess of an annual limit of $1,000,000 after December 31, 2022.
 
During
the year ended March 31, 2024, the Company repurchased 50,101 shares for the treasury account at an aggregate cost of $585,035, an average
price of $11.68 per share per share. During the year ended March 31, 2023, the Company repurchased 18,416 shares for the treasury account
at an aggregate cost of $244,494, an average price of $13.28 per share per share. Subsequently, in April 2024, the Company’s Board
of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s common stock, par value, $0.50, for the
treasury account. This authorization replaced the previously authorized $1,000,000 common stock repurchase program which had $414,965
remaining at the time it was replaced. Also in April 2024, the Company repurchased 13,766 shares for the treasury account at an aggregate
cost of $188,637.
 

F-14
 

 
10.
Stock-based Compensation 
 
In
September 2019, the Company adopted the 2019 Employee Incentive Stock Plan (the “2019 Plan”). The 2019 Plan provides for
the award of stock options up to 200,000 shares and includes option awards as well as stock awards. Option awards are granted with the
restriction of requiring payment for the shares. Stock awards are granted without restrictions and without payment by the recipient.
Neither option awards nor stock awards may exceed 25,000 shares granted to any one individual in any fiscal year. Stock options may be
an incentive stock option or a nonqualified stock option. Options to purchase common stock under the plan are granted at the fair market
value of the common stock at the date of grant, become exercisable to the extent of 25% of the shares optioned on each of four anniversaries
of the date of grant, expire ten years from the date of grant and are subject to forfeiture if employment terminates. The 2019 Plan expires
ten years from the date of adoption. According to the Company’s employee stock incentive plan, new shares will be issued upon the
exercise of stock options and the Company can repurchase shares exercised under the plan.
 
During
the year ended March 31, 2024, the Compensation Committee of the Board of Directors approved and the Company granted 32,000 stock options.
During the year ended March 31, 2023, the Compensation Committee of the Board of Directors approved and the Company granted 31,000 stock
options.
 
The
plan also provides for the granting of stock awards. No stock awards were granted during fiscal 2024 and 2023.
 
The
Company recognized compensation expense of $229,799 and $142,783 related to vesting stock options in general and administrative expense
in the Consolidated Statements of Operations for fiscal 2024 and 2023, respectively. The total cost related to non-vested awards not
yet recognized at March 31, 2024 totals $502,361, which is expected to be recognized over a weighted average of 2.46 years.
 
The
fair value of each stock option is estimated on the date of grant using the Binomial valuation model. Expected volatilities are based
on historical volatility of the Company’s stock over the contractual term of 120 months and other factors. The Company uses historical
data to estimate option exercise and employee termination within the valuation model. The expected term of options granted is derived
from the output of the option valuation model and represents the period of time that options granted are expected to be outstanding.
The risk-free rate for periods within the contractual life of the option is based on the U.S. Treasury yield curve in effect at the time
of grant. Since the Company has only declared a special one-time dividend, no dividend yield was used in the calculation on current options
understanding. Actual value realized, if any, is dependent on the future performance of the Company’s common stock and overall
stock market conditions. There is no assurance the value realized by an optionee will be at or near the value estimated by the Binomial
model.
 
Included
in the following table is a summary of the grant-date fair value of stock options granted and the related assumptions used in the Binomial
models for stock options granted in fiscal 2024 and 2023. All such amounts represent the weighted average amounts for each period.
 Schedule
of Grant-date Fair Value of Stock Options Granted and Assumptions Used Binominal Models


  
For the year ended March 31, 

  
2024  
2023 

Grant-date fair value 
$8.73  
$12.44 

Volatility factor 
 56.52% 
 57.3%

Dividend yield 
 -  
 - 

Risk-free interest rate 
 3.44% 
 3.15%

Expected term (in years) 
 6.25  
 6.25 

 
No
forfeiture rate is assumed for stock options granted to directors or employees due to the forfeiture rate history for these types of
awards. During the year ended March 31, 2024, there were no stock options forfeited or expired. During the year ended March 31, 2023,
1,000 unvested stock options were forfeited due to the resignation of an employee.
 

F-15
 

 
The
following table is a summary of activity of stock options for the years ended March 31, 2024 and 2023:
 Summary of Activity of Stock Options


  
Number of
 Shares  
Weighted
 Average
 Exercise Price 
Per Share  
Weighted
 Aggregate 
Average 
Remaining Contract Life in Years  
Intrinsic
 Value 

Outstanding at April 1, 2022 
 114,250  
$5.51  
 7.40  
$1,221,670 

Granted 
 31,000  
 18.05  
    
   

Exercised 
 (5,000) 
 3.34  
    
   

Forfeited or Expired 
 (1,000) 
 7.22  
    
   

Outstanding at March 31, 2023 
 139,250  
$8.36  
 7.04  
$419,853 

Granted 
 32,000  
 12.68  
    
   

Exercised 
 (5,500) 
 3.58  
    
   

Forfeited or Expired 
 -  
 -  
    
   

Outstanding at March 31, 2024 
 165,750  
$9.36  
 6.62  
$103,275 

  
    
    
    
   

Vested at March 31, 2024 
 95,500  
$6.26  
 5.26  
$355,253 

Exercisable at March 31, 2024 
 95,500  
$6.26  
 5.26  
$355,253 

 
During
the year ended March 31, 2024, stock options covering 5,500 shares were exercised with a total intrinsic value of $37,566. The Company
received proceeds of $19,662 from these exercises. During the year ended March 31, 2023, stock options covering 5,000 shares were exercised
with a total intrinsic value of $47,575. The Company received proceeds of $16,700 from these exercises. Subsequently, in April 2024,
stock options covering 12,367 shares were exercised. The Company received proceeds of $77,641 from these exercises.
Other
information pertaining to option activity was as follows during the year ended March 31:
 Schedule of Other Information Pertaining to Option Activity


  
2024  
2023 

Weighted average grant-date fair value of stock options granted (per share) 
$8.73  
$12.44 

Total fair value of options vested 
$234,025  
$102,348 

Total intrinsic value of options exercised 
$37,566  
$47,575 

 
The
following table summarizes information about options outstanding at March 31, 2024:
 Summary of Information About Options Outstanding


Range of 
Exercise 
Prices  
Number 
of 
Options  
Weighted Average
 Exercise Price 
Per Share  
Weighted Average
 Remaining Contract
 Life in Years  
Aggregate 
Intrinsic 
Value 

$3.34 – 4.83  
 27,500  
$3.34  
    
   

 4.84 – 5.97  
 36,250  
 4.84  
    
   

 5.98 – 7.00  
 9,000  
 7.00  
    
   

 7.01 – 8.51  
 30,000  
 8.51  
    
   

 8.52 – 18.05  
 63,000  
 15.32  
    
   

$ 3.34 – 18.05  
 165,750  
$9.36  
 6.62  
$103,275 

 
Outstanding
options at March 31, 2023 expire between August 2024 and April 2033 and have exercise prices ranging from $3.34 to $18.05.
 
11.
Related Party Transactions
 
Related
party transactions for the Company primarily relate to shared office expenditures in addition to administrative and operating expenses
paid on behalf of the principal stockholder. The total billed to and reimbursed by the stockholder for the years ended March 31, 2024
and 2023 were $23,379 and $47,055, respectively. The principal stockholder pays for his share of the lease amount for the shared office
space directly to the lessor. Amounts paid by the principal stockholder directly to the lessor for the year ending March 31, 2024 and
2023 were $15,572.
 

F-16
 

 
12.
Leases
 
The
Company leases approximately 4,160 rentable square feet of office space from an unaffiliated third party for the corporate office located
in Midland, Texas. This includes 1,112 square feet of office space shared with and paid by our principal shareholder. The lease does
not include an option to renew and is a 36-month lease that was to expire in May 2021. In June 2020, in exchange for a reduction in rent
for the months of June and July 2020, the Company agreed to a 2-month extension to its current lease agreement at the regular monthly
rate extending its current lease expiration date to July 2021. In June 2021, the Company agreed to extend its current lease at a flat
(unescalated) rate for 36 months. The amended lease now expires on July 31, 2024.
 
The
Company determines an arrangement is a lease at inception. Operating leases are recorded in operating lease right-of-use asset, operating
lease liability, current, and operating lease liability, long-term on the consolidated balance sheet.
 
Operating
lease right-of-use assets represent the Company’s right to use an underlying asset for the lease term and lease liabilities represent
its obligation to make lease payments arising from the lease. Operating lease assets and liabilities are recognized at the commencement
date based on the present value of lease payments over the lease term. As the Company’s lease does not provide an implicit rate,
the Company uses the incremental borrowing rate based on the information available at commencement date in determining the present value
of lease payments. The incremental borrowing rate used at adoption was 3.75%. Significant judgement is required when determining the
incremental borrowing rate. Rent expense for lease payments is recognized on a straight-line basis over the lease term.
 
The
balance sheet classification of lease assets and liabilities was as follows:
 Schedule
of Operating Lease Assets and Liabilities


  
March 31, 2024 

Assets 
   

Operating lease right-of-use asset, beginning balance 
$75,629 

Current period amortization 
 (56,366)

Lease amendment 
 - 

Total operating lease right-of-use asset 
$19,263 

  
   

Liabilities 
   

Operating lease liability, current 
$19,263 

Operating lease liability, long term 
 - 

Total lease liabilities 
$19,263 

 
Future
minimum lease payments as of March 31, 2024 under non-cancellable operating leases are as follows:
 Schedule of Future Minimum Lease Payments


  
Lease Obligation 

Fiscal Year Ended March 31, 2025 
$19,413 

Total lease payments 
$19,413 

Less: imputed interest 
 (150)

Operating lease liability 
 19,263 

Less: operating lease liability, current 
 (19,263)

Operating lease liability, long term 
$- 

 
Net
cash paid for our operating lease for the year ended March 31, 2024 and 2023 was $42,668. Rent expense, less sublease income of $15,572
is included in general and administrative expenses.
 
13.
Oil and Gas Reserve Data (Unaudited)
 
The
estimates of the Company’s proved oil and gas reserves, which are located entirely within the United States, were prepared in accordance
with the generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC. The
estimates as of March 31, 2024 and 2023 were based on evaluations prepared by Russell K. Hall and Associates, Inc. The services provided
by Russell K. Hall and Associates, Inc. are not audits of our reserves but instead consist of complete engineering evaluations of the
respective properties. For more information about their evaluations performed, refer to the copy of their report filed as an exhibit
to this Annual Report on Form 10-K. Management emphasizes that reserve estimates are inherently imprecise and that estimates of new discoveries
are more imprecise than those of currently producing oil and natural gas properties. Accordingly, these estimates are expected to change
as additional information becomes available in the future.
 

F-17
 

 
The
following table presents the weighted average first-day-of-the-month prices used for oil and gas reserve preparation, based upon SEC
guidelines.
 Schedule of Weighted Average First-day-of-the-month Prices Used for Oil and Gas Reserve


  
March 31,  
  

  
2024  
2023  
% Change 

Prices utilized in the reserve estimates before adjustments: 
    
    
   

Oil per Bbl 
$73.96  
$87.45  
 (15)%

Natural gas per MMBtu 
$2.45  
$5.96  
 (59)%

 
The
Company’s total estimated proved reserves at March 31, 2024 were approximately 1.547 MBOE of which 51% was oil and natural gas
liquids and 49% was natural gas.
 
Changes
in Proved Reserves:
 Schedule of Changes in Proved Reserve


  
Oil (Bbls)  
Natural Gas (Mcf) 

Proved Developed and Undeveloped Reserves: 
    
   

As of April 1, 2022 
 809,000  
 4,842,000 

Revision of previous estimates 
 (108,000) 
 328,000 

Purchase of minerals in place 
 31,000  
 125,000 

Extensions and discoveries 
 69,000  
 188,000 

Sales of minerals in place 
 -  
 - 

Production 
 (74,000) 
 (534,000)

As of March 31, 2023 
 727,000  
 4,949,000 

Revision of previous estimates 
 (86,000) 
 (463,000)

Purchase of minerals in place 
 24,000  
 121,000 

Extensions and discoveries 
 199,000  
 437,000 

Sales of minerals in place 
 (3,000) 
 (4,000)

Production 
 (70,000) 
 (503,000)

As of March 31, 2024 
 791,000  
 4,537,000 

 
Proved
developed reserves are those expected to be recovered through existing wells, equipment and operating methods. Proved undeveloped reserves
(“PUD”) are proved reserves that are expected to be recovered from new wells on undrilled acreage or from existing wells
where a relatively major expenditure is required for recompletion within five years of the date of their initial recognition. Moreover,
the Company may be required to write down its proved undeveloped reserves if the operators do not drill on the reserves within the required
five-year timeframe. Such downward revisions are primarily attributable to a decrease in crude oil and natural gas prices and partially
the result of reserves written off due to the five-year limitation and the change in the timing of new development. The reserves written off were primarily
royalty interests on leases in DeSoto Parish, Louisiana and Karnes County, Texas which are held by production and still in place to be
developed in the future.
 
Summary
of Proved Developed and Undeveloped Reserves as of March 31, 2024 and 2023:
 Summary of Proved Developed and Undeveloped Reserves


  
Oil (Bbls)  
Natural Gas (Mcf) 

Proved Developed Reserves: 
    
   

As of April 1, 2022 
 428,280  
 3,583,470 

As of March 31, 2023 
 486,770  
 3,971,370 

As of March 31, 2024 
 444,610  
 3,566,240 

Proved Undeveloped Reserves: 
    
   

As of April 1, 2022 
 380,550  
 1,258,210 

As of March 31, 2023 
 240,060  
 978,010 

As of March 31, 2024 
 346,330  
 970,880 

 

F-18
 

 
At
March 31, 2024, the Company reported estimated PUDs of 508 MBOE, which accounted for 33% of its total estimated proved oil and gas reserves.
This figure primarily consists of a projected 64 new wells (205 MBOE) operated by others, 14 wells are currently being drilled with plans
for 37 wells to follow in fiscal 2025, 104 wells in fiscal 2026 and 6 wells in fiscal 2027. The cost of these projects would be funded,
to the extent possible, from existing cash balances, cash flow from operations and bank borrowings. The remainder may be funded through
non-core asset sales and/or sales of our common stock.
 
The
following table discloses the Company’s progress toward the conversion of PUDs during fiscal 2024.
 
Progress
of Converting Proved Undeveloped Reserves:
 Schedule of Progress of Converting Proved Undeveloped Reserves


  
Oil & Natural  
Future 

  
Gas
 (BOE)  
Development Costs 

PUDs, beginning of year 
 403,065  
$3,837,540 

Revision of previous estimates 
 (38,780) 
 272,365 

Sales of reserves 
 -  
 - 

Conversions to PD reserves 
 (61,606) 
 (935,590)

Additional PUDs added 
 205,462  
 2,307,162 

PUDs, end of year 
 508,141  
$5,481,477 

 
Estimated
future net cash flows represent an estimate of future net revenues from the production of proved reserves using average prices for 2024
and 2023 along with estimates of the operating costs, production taxes and future development costs necessary to produce such reserves.
No deduction has been made for depreciation, depletion or any indirect costs such as general corporate overhead or interest expense.
 
Operating
costs and production taxes are estimated based on current costs with respect to producing oil and natural gas properties. Future development
costs including abandonment costs are based on the best estimate of such costs assuming current economic and operating conditions. The
future cash flows estimated to be spent to develop the Company’s share of proved undeveloped properties through March 31, 2027
are $5,481,477.
 
Income
tax expense is computed based on applying the appropriate statutory tax rate to the excess of future cash inflows less future production
and development costs over the current tax basis of the properties involved, less applicable carryforwards.
 
The
future net revenue information assumes no escalation of costs or prices, except for oil and natural gas sales made under terms of contracts
which include fixed and determinable escalation. Future costs and prices could significantly vary from current amounts and, accordingly,
revisions in the future could be significant.
 
The
current reporting rules require that year end reserve calculations and future cash inflows be based on the 12-month average market prices
for sales of oil and gas on the first calendar day of each month during the fiscal year discounted at 10% per year and assuming continuation
of existing economic conditions. The average prices used for fiscal 2024 were $76.88 per bbl of oil and $2.75 per mcf of natural gas.
The average prices used for fiscal 2023 were $92.02 per bbl of oil and $5.68 per mcf of natural gas.
 
The
standardized measure of discounted future net cash flows is computed by applying the 12-month unweighted average of the first day of
the month pricing for oil and natural gas (with consideration of price changes only to the extent provided by contractual arrangements)
to the estimated future production of proved oil and natural gas reserves, less estimated future expenditures (based on year end costs)
to be incurred in developing and producing the proved reserves, discounted using a rate of 10% per year to reflect the estimated timing
of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and
natural gas properties plus available carryforwards and credits and applying the current tax rate to the difference.
 
The
basis for this table is the reserve studies prepared by an independent petroleum engineering consultant, which contain imprecise estimates
of quantities and rates of production of reserves. Revisions of previous year estimates can have a significant impact on these results.
Also, exploration costs in one year may lead to significant discoveries in later years and may significantly change previous estimates
of proved reserves and their valuation. Therefore, the standardized measure of discounted future net cash flow is not necessarily indicative
of the fair value of proved oil and gas properties.
 

F-19
 

 
The
following information is based on the Company’s best estimate of the required data for the Standardized Measure of Discounted Future
Net Cash Flows as of March 31, 2024 and 2023 in accordance with ASC 932, “Extractive Activities – Oil and Gas” which
requires the use of a 10% discount rate. This information is not the fair market value, nor does it represent the expected present value
of future cash flows of the Company’s proved oil and gas reserves.
 
Standardized
Measure of Discounted Future Net Cash Flows Relating to Proved Reserves:
 Schedule of Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Reserves


  
2024  
2023 

  
March 31 

  
2024  
2023 

Future cash inflows 
$73,290,000  
$94,972,000 

Future production costs and taxes 
 (21,634,000) 
 (23,800,000)

Future development costs 
 (5,481,000) 
 (4,280,000)

Future income taxes 
 (7,067,000) 
 (11,284,000)

Future net cash flows 
 39,108,000  
 55,608,000 

Annual 10% discount for estimated timing of cash flows 
 (14,480,000) 
 (22,793,000)

Standardized measure of discounted future net cash flows 
$24,628,000  
$32,815,000 

 
Changes
in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves:
 Schedule of Changes in Standardized Measure of Discounted Future Net Cash Flows to Proved Oil and Gas Reserves


  
2024  
2023 

  
March 31 

  
2024  
2023 

Sales of oil and gas produced, net of production costs 
$(4,936,000) 
$(7,661,000)

Net changes in price and production costs 
 (14,394,000) 
 8,937,000 

Changes in previously estimated development costs 
 (77,000) 
 413,000 

Revisions of quantity estimates 
 (3,620,000) 
 (4,313,000)

Net change due to purchases and sales of minerals in place 
 1,146,000  
 2,030,000 

Extensions and discoveries, less related costs 
 7,208,000  
 3,277,000 

Net change in income taxes 
 2,208,000  
 (1,801,000)

Accretion of discount 
 2,908,000  
 3,947,000 

Changes in timing of estimated cash flows and other 
 1,370,000  
 2,066,000 

Changes in standardized measure 
 (8,187,000) 
 6,895,000 

Standardized measure, beginning of year 
 32,815,000  
 25,920,000 

Standardized measure, end of year 
$24,628,000  
$32,815,000 

 
14.
Subsequent Events
 
On
April 30, 2024, the Company announced that its Board of Directors declared a regular annual dividend of $0.10 per common share to its shareholders
of record at the close of business on May 21, 2024. The regular annual dividend was paid on June 4, 2024.
 
In
April 2024, the Company’s Board of Directors authorized the use of up to $1,000,000 to repurchase shares of the Company’s
common stock, par value, $0.50, for the treasury account. Also in April 2024, the Company repurchased 13,766 shares for the treasury
account at an aggregate cost of $188,637, an average price of $13.70 per share.
 
In
April 2024, the Company acquired small royalty (mineral) interests in 21 wells operated by Anadarko Petroleum and Cimarex Energy and
located in Reeves County, Texas for a purchase price of $158,000.
 
In
April 2024, stock options covering 12,367 shares were exercised. The Company received proceeds of $77,641 from these exercises.
 
In
April 2024, Mexco expended approximately $207,800 to participate in the drilling of nine horizontal wells located in the Delaware Basin
in Lea County, New Mexico.
 
In
May 2024, the Company funded another $200,000 toward its $2,000,000 equity investment in a limited liability company.
 
In
May 2024, the Company expended approximately $90,000 to complete 2 horizontal wells in the Bone Spring Sand formation of the Delaware
Basin in Lea County, New Mexico.
 
The
Company completed a review and analysis of all events that occurred after the consolidated balance sheet date to determine if any such
events must be reported and has determined that there are no other subsequent events to be disclosed.
 

F-20
 

 
INDEX
TO EXHIBITS
 


Exhibit

 
 

Number
 
 

 
 
 

3.1
 
Restated
    Articles of Incorporation of Mexco Energy Corporation filed as Exhibit 3.1 to the Company’s Annual Report on Form 10-K dated
    June 24, 1998, and incorporated herein by reference.

 
 
 

3.2
    
 
Amended Bylaws of Mexco Energy Corporation as amended on September 13, 2011 filed as Exhibit 3.1 to the Company’s Current Report on Form 8-K dated September 14, 2011, and incorporated herein by reference.

 
 
 

10.1
 
2009 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 15, 2009, and incorporated herein by reference.

 
 
 

10.2
 
2019 Employee Incentive Stock Plan of Mexco Energy Corporation filed as Exhibit A to the Company’s Proxy Statement on Form 14C dated July 16, 2019, and incorporated herein by reference.

 
 
 

10.3
 
Loan Agreement dated December 28, 2018 between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.1 to the Company’s Current Report on Form 8-K dated December 31, 2018, and incorporated herein by reference.

 
 
 

10.4
 
First Amendment to Loan Agreement dated February 28, 2020 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.4 to the Company’s Annual Report on form 10-K filed on June 26, 2020, and incorporated herein by reference.

 
 
 

10.5
 
Second Amendment to Loan Agreement dated March 28, 2023 to the Loan Agreement between West Texas National Bank and Mexco Energy Corporation filed as Exhibit 10.5 to the Company’s Annual Report on Form 10-K dated June 26, 2023, and incorporated herein by reference.

 
 
 

14.1
 
Code of Business Conduct and Ethics of Mexco Energy Corporation filed with the Company’s Quarterly Report on Form 10-Q filed on November 15, 2004, and incorporated herein by reference.

 
 
 

21.1
 
Subsidiaries of Mexco Energy Corporation

 
 
 

23.1
 
Consent of Weaver and Tidwell, L.L.P., Independent Registered Public Accounting Firm

 
 
 

23.2
 
Consent of Russell K. Hall & Associates, Inc., Independent Petroleum Engineers

 
 
 

31.1
 
Certification of the Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 
 
 

31.2
 
Certification of the Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

 
 
 

32.1
 
Certification of the Chief Executive Officer and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

 
 
 

99.1
 
Report of Russell K. Hall & Associates, Inc., Independent Petroleum Engineering Firm

 
 
 

101.INS
 
Inline
    XBRL Instance Document

 
 
 

101.SCH
 
Inline
    XBRL Taxonomy Extension Schema Document

 
 
 

101.CAL
 
Inline
    XBRL Taxonomy Extension Calculation Linkbase Document

 
 
 

101.DEF
 
Inline
    XBRL Taxonomy Extension Definition Linkbase Document

 
 
 

101.LAB
 
Inline
    XBRL Taxonomy Extension Label Linkbase Document

 
 
 

101.PRE
 
Inline
    XBRL Taxonomy Extension Presentation Linkbase Document

 
 
 

104
 
Cover
    Page Innteractive Data File (embedded within the Inline XBRL and contained in Exhibit 101)

 

38

 


